Fracturing Engineering Manual - 4243456 - 02 [PDF]

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Fracturing Engineering Manual Preface



The intention of the Fracturing Engineering Manual is to document Dowell fracturing engineering technology so that it will be uniformly available to Dowell personnel. The nature and application of the services, techniques, and associated products used in fracturing treatment design, execution, and evaluation are included. The manual is to be instructional in nature. Although the emphasis will be on application of technology rather than technical details, some technical details are not always available everywhere and are included. Every attempt has been made to make the Fracturing Engineering Manual as up to date as possible, realizing that every manual at the time of its publication is partially out of date. Each section in the Fracturing Engineering Manual will be periodically reviewed. Revisions and additions will be distributed when necessary. This Preface is hyperlinked to the Master Table of Contents which hyperlinks to all the sections in the manual. Click on the MASTER TABLE OF CONTENTS below to jump to that location.



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MASTER TABLE OF CONTENTS Section 100 Reservoir Evaluation 1 Introductory Summary................................................................................................................ 4 2 Well Performance ...................................................................................................................... 5 2.1 Inflow Performance .............................................................................................................. 6 2.2 Tubing Intake ....................................................................................................................... 8 3 Well Test Interpretation............................................................................................................ 10 3.1 Critical Variables ................................................................................................................ 11 3.2 Flow Regimes .................................................................................................................... 13 3.3 Boundary Effects................................................................................................................ 14 3.4 Diagnostic Plots ................................................................................................................. 15 3.5 Type Curves....................................................................................................................... 18 3.6 Computational System ....................................................................................................... 21 3.7 Steps for Analysis .............................................................................................................. 27 3.8 Example Analysis............................................................................................................... 30 4 Economic Analysis ................................................................................................................... 38 4.1 FracNPV Software ............................................................................................................. 40 5 Application ............................................................................................................................... 48 6 Equation Summary .................................................................................................................. 55 6.1 Oil IPR Equations............................................................................................................... 55 6.1.1 Darcy's Law .............................................................................................................. 55 6.1.2 Vogel Test Data ( Pr ≤ pb ) ........................................................................................ 55 (P p ) 6.1.3 Combination Vogel = Darcy Test Data r ≥ b ...................................................... 55 6.1.4 Jones IPR ................................................................................................................. 57 6.2 Gas IPR Equations............................................................................................................. 58 6.2.1 Darcy's Law (Gas) .................................................................................................... 58 6.2.2 Jones' Gas IPR (General Form) ............................................................................... 58 6.3 Backpressure Equation ...................................................................................................... 59 6.4 Transient Period Equations................................................................................................ 60 6.4.1 Time to Pseudosteady State..................................................................................... 60 6.4.2 Oil IPR (Transient) .................................................................................................... 60 6.4.3 Gas IPR (Transient).................................................................................................. 61 6.5 Completion Pressure Drop Equations................................................................................ 61 6.5.1 Gravel-Packed Wells ................................................................................................ 61 6.5.2 Open Perforation Pressure Drop .............................................................................. 63 Section 100 Figures Fig. 1. Pressure losses in complete systems (after Mach, Proano and Brown)........................... 5 Fig. 2. Location of various nodes (Mach et al., 1981). ................................................................. 6 Fig. 3. Typical IPR curve. ............................................................................................................. 7 Fig. 4. Vogel's composite IPR. ..................................................................................................... 8 Fig. 5. Vertical multiphase flow: How to find the flowing bottomhole pressure. .......................... 9 DOWELL CONFIDENTIAL



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Fig. 6. Tubing intake curve. ..........................................................................................................9 Fig. 7. Deliverability of the producing system. ............................................................................10 Fig. 8. Well log............................................................................................................................12 Fig. 9. Well log............................................................................................................................12 Fig. 10. Radial flow. ....................................................................................................................13 Fig. 11. Linear flow in the formation. ..........................................................................................14 Fig. 12. Bilinear flow. ..................................................................................................................14 Fig. 13. Conditions associated with the boundries. ....................................................................15 Fig. 14. Pressure change and elapsed time to use in a drawdown. ...........................................16 Fig. 15. Log-Log plot. .................................................................................................................17 Fig. 16. Pressure change and elapsed time. ..............................................................................17 Fig. 17. Complete log-log behavior.............................................................................................17 Fig. 18. This is a reproduction from a type curve described in World Oil, (Oct. 1983). ..............19 Fig. 19. Series of pressure, pressure derivative, and specialized plots for common reservoir features..........................................................................................................20 Fig. 20. Diagnostic log-log plot. ..................................................................................................21 Fig. 21. Two Horner plots. ..........................................................................................................22 Fig. 22. Model-Verified Interpretation. ........................................................................................23 Fig. 23. Conceptual model catalog. ............................................................................................24 Fig. 24. NODAL plot. ..................................................................................................................25 Fig. 25. Sequence simulation. ....................................................................................................25 Fig. 26. Simulated validation. .....................................................................................................26 Fig. 27. PVT plot.........................................................................................................................26 Fig. 28. Matching a diagnostic log-log plot to a type curve.........................................................29 Fig. 29. Matching a diagnostic log-log plot to a type curve.........................................................29 Fig. 30. Log-Log Plot ..................................................................................................................30 Fig. 31. Generated type curve with the log-log diagnostic match...............................................32 Fig. 32. Semilog presentation using a superposition type curve and the data points from the buildup. ...........................................................................................................33 Fig. 33. Cartesian plot of the simulated pressure and the actual measured data. .....................33 Fig. 34. Decline curve and sensitivity plot. .................................................................................34 Fig. 35. Decline curve and sensitivity plot. .................................................................................34 Fig. 36. Sensitivity plot................................................................................................................35 Fig. 37. Sensitivity plot................................................................................................................35 Fig. 38. Sensitivity plot................................................................................................................36 Fig. 39. Sensitivity plot................................................................................................................36 Fig. 40. Sensitivity plot................................................................................................................37 Fig. 41. Plot of the transient IPR curves with the tubing intake and wellhead pressure of 875 psi. ......................................................................................................37 Fig. 42. Transient IPR plot for the same tubing, but using different wellhead pressures to generate the plot shown in Fig. 32................................................................................38 Fig. 43. Conceptual NPV calculation. Case A: revenue is larger than the cost, resulting in a positive NPV; Case B: revenue is less than the cost, resulting in a negative NPV.......40



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Fig. 44. Components of the NPV calculation. ............................................................................ 41 Fig. 45. Fracture in a bounded reservoir.................................................................................... 41 Fig. 46. Constant-rate type curve for finite-conductivity fracture  closed square system (xe/ye = 1). ...................................................................................................................42 Fig. 47. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 2). ...................................................................................................................42 Fig. 48. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 4). ...................................................................................................................43 Fig. 49. Transient IPR for a fracture well in a closed square reservoir. ..................................... 44 Fig. 50. Tubing intake curve....................................................................................................... 45 Fig. 51. FracNPV analysis for one, two and three years versus fracture length. ....................... 46 Fig. 52. Cumulative production versus fracture length............................................................... 46 Fig. 53. Production decline versus time. .................................................................................... 47 Fig. 54. Cumulative production versus time. .............................................................................. 47 Fig. 55. Well performance tracking form. ................................................................................... 51 Fig. 56. Well performance tracking form. ................................................................................... 53 Section 100 Tables Table 1. Results of Buildup Test ................................................................................................ 31 Table 2. Maximum Fracture Lengths for Drainage Shapes ....................................................... 43 Section 200 Rock Mechanics 1 Introductory Summary................................................................................................................ 3 2 Lithology..................................................................................................................................... 3 3 Basic Concepts .......................................................................................................................... 9 3.1 Stress Concept .................................................................................................................... 9 3.2 Stress Definition ................................................................................................................. 10 3.3 Strain.................................................................................................................................. 17 3.4 Modulus/Poisson Effect...................................................................................................... 18 3.5 Effective Stress .................................................................................................................. 22 3.6 Failure Criteria ................................................................................................................... 23 4 Measurement of Rock Properties ............................................................................................ 27 4.1 Typical Properties .............................................................................................................. 29 4.2 Toughness ......................................................................................................................... 31 5 Determining in-Situ Stress ....................................................................................................... 35 5.1 Core Tests ......................................................................................................................... 35 5.2 Microfracturing ................................................................................................................... 42 5.3 Pump-In/Flowback Test ..................................................................................................... 44 5.4 Logs ................................................................................................................................... 44 6 Fracture Height (Post).............................................................................................................. 47 6.1 Radioactive Tracer............................................................................................................. 47 6.2 Temperature ...................................................................................................................... 50



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Section 200 Figures Fig. 1. Example Litho-Density* log and CNL* Compensated Neutron log. ...................................6 Fig. 2. Example crossplot chart. ...................................................................................................7 Fig. 3. Lithology log. .....................................................................................................................8 Fig. 4. Triaxial stress. .................................................................................................................10 Fig. 5. Randomly oriented plane.................................................................................................11 Fig. 6. Rectangular axis system. ................................................................................................12 Fig. 7. Two-dimensional systems. ..............................................................................................13 Fig. 8. Stress charts....................................................................................................................15 Fig. 9. Strain measurement. .......................................................................................................17 Fig. 10. Typical stress/strain curves. ..........................................................................................18 Fig. 11. Stress strain relationship. ..............................................................................................20 Fig. 12. Compressional force......................................................................................................21 Fig. 13. Principal stresses in a triaxial application. .....................................................................23 Fig. 14. Mohr's circle. .................................................................................................................24 Fig. 15. Mohr failure envelope. ...................................................................................................25 Fig. 16. Typical failure envelope.................................................................................................26 Fig. 17. Dynamic elastic properties. ...........................................................................................27 Fig. 18. Permeability versus confining stress for a fractured rock specimen..............................30 Fig. 19. Stress concentration near the tip of a crack. .................................................................32 Fig. 20. Modified ring. .................................................................................................................33 Fig. 21. Load/displacement curve obtained during a Modified Ring Test...................................33 Fig. 22. Drawing of the LVDT* displacement gauge developed at the Sandia National Laboratory1....................................................................................................................36 Fig. 23. Typical ASR curve. ........................................................................................................37 Fig. 24. Anelastic strain recovery measurements.......................................................................38 Fig. 25. Gage pattern. ................................................................................................................39 Fig. 26. Typical DSCA plots........................................................................................................40 Fig. 27. Stereoplot. .....................................................................................................................41 Fig. 28. Idealized plot. ................................................................................................................42 Fig. 29. Microfrac test. ................................................................................................................43 Fig. 30. Fracture-height log. .......................................................................................................46 Fig. 31. Two-isotope tracking of a two-stage fracture treatment. ...............................................48 Fig. 32. Two-isotope tracking of a single-stage fracture treatment.............................................49 Fig. 33. Temperature survey with RA tracer...............................................................................51 Section 200 Tables Table 1. X-Ray Diffraction Analysis ..............................................................................................4 Table 2. Dynamic Versus Static Tests........................................................................................28 Section 300 Fracture Modeling 1 Introductory Summary ................................................................................................................2 2 Concepts ....................................................................................................................................3 2.1 Fundamental Laws ...............................................................................................................4 2.2 Constitutive Laws .................................................................................................................4 2.3 Fracture Propagation............................................................................................................6 DOWELL CONFIDENTIAL



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3 Hydraulic Fracturing Models ...................................................................................................... 9 3.1 Two-Dimensional (2D) ....................................................................................................... 11 3.2 Pseudo Three-Dimensional (P-3D) .................................................................................... 15 3.3 Planar Three-Dimensional (PL-3D).................................................................................... 18 3.4 Fully Three-Dimensional (3D) ............................................................................................ 19 4 Examples ................................................................................................................................. 20 4.1 Case History ...................................................................................................................... 20 4.2 Model Comparisons ........................................................................................................... 28 Section 300 Figures Fig. 1. Modes of loading............................................................................................................... 7 Fig. 2. Fracture divided into elements.......................................................................................... 9 Fig. 3. Representation of a planar fracture. ............................................................................... 10 Fig. 4. KGD geometry. ............................................................................................................... 11 Fig. 5. PKN geometry................................................................................................................. 12 Fig. 6. 2D and radial Sneddon cracks. ....................................................................................... 13 Fig. 7. Elliptical profile (P-3D)..................................................................................................... 17 Fig. 8. Example grid (PL-3D model)........................................................................................... 18 Fig. 9. Fracture profile (PL-3D model). ...................................................................................... 19 Fig. 10. Permeability, thickness and stress profile. .................................................................... 20 Fig. 11. Computed values for Young's modulus and Poisson's ratio. ........................................ 21 Fig. 12. Profile of bottomhole, casing and tubing pressures. ..................................................... 24 Fig. 13. Pressure match for bottomhole and casing pressure. .................................................. 24 Fig. 14. Fracture profile.............................................................................................................. 25 Fig. 15. Fracture width profile. ................................................................................................... 25 Fig. 16. Match of net pressure for calibration fracture and main fracture. ................................. 26 Fig. 17. Fracture profile.............................................................................................................. 26 Fig. 18. Reservoir model for final history match......................................................................... 28 Fig. 19. TRIFRAC length and width profile................................................................................. 32 Fig. 20. STIMPLAN length and width. ........................................................................................ 32 Fig. 21. FRACPRO length and width profile............................................................................... 33 Fig. 22. GOHFER length and width profile................................................................................. 33 Fig. 23. TERRAFRAC length profile........................................................................................... 34 Fig. 24. STIMPLAN length and width profile. ............................................................................. 34 Fig. 25. MEYER length and width profile. .................................................................................. 35 Fig. 26. Ohio state length profile. ............................................................................................... 35 Section 300 Tables Table 1. Comparison Of Stress.................................................................................................. 22 Table 2. Permeability and Fluid Loss ......................................................................................... 22 Table 3. Design Information....................................................................................................... 23 Table 4. Fracture Model Comparison Runs ............................................................................... 30 Table 5. Fracture Model Comparison Runs ............................................................................... 31



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Section 400 Treatment Design 1 Introductory Summary ................................................................................................................3 1.1 References ...........................................................................................................................3 2 Adaptive Design Methodology....................................................................................................6 2.1 Setting Characterization .......................................................................................................7 2.2 Setting Modelization .............................................................................................................8 2.3 Adaptive Treatment Design ................................................................................................10 3 Data Collection .........................................................................................................................10 4 Fracturing Fluid Selection.........................................................................................................12 4.1 Fracturing Fluid Selection Guide ........................................................................................13 4.2 Water Sensitivity of the Reservoir Rock .............................................................................16 4.3 Rheological Properties and Viscosity Requirements ..........................................................17 4.4 Fluid Friction Pressure........................................................................................................18 4.5 Fluid Compatibility with Reservoir Fluid and Rock..............................................................20 4.6 Rheology Selection.............................................................................................................20 4.7 Fracturing Fluid Additive Selection .....................................................................................21 5 Proppant Selection ...................................................................................................................21 5.1 Proppant Selection Methodology........................................................................................22 6 FracCADE Software .................................................................................................................28 6.1 The FGS Module ................................................................................................................29 6.2 The MLF Module ................................................................................................................29 6.3 The FracNPV Module .........................................................................................................30 6.4 The INVERSE Module........................................................................................................30 6.5 The PLACEMENT Module..................................................................................................31 6.5.1 PLACEMENT I ..........................................................................................................31 6.5.2 PLACEMENT II .........................................................................................................31 6.6 Additional FracCADE Modules ...........................................................................................31 7 Equations..................................................................................................................................33 7.1 Basic Equations..................................................................................................................33 7.2 Design Equations ...............................................................................................................34 7.3 Proppant Equations ............................................................................................................37 8 Proppant Flowback...................................................................................................................38 9 Refracturing ..............................................................................................................................39 9.1 Candidate Selection ...........................................................................................................40 9.2 Refracturing Design Methodology ......................................................................................41 9.2.1 Estimation of Recoverable Reserves ........................................................................41 9.2.2 Estimation of the Present Fracture Geometry...........................................................42 9.2.3 Determining the Average Reservoir Pressure...........................................................44 9.2.4 Estimating Production Response From Refracturing ................................................44 9.3 The Effects of Fractured Well Pressure Distributions on Design........................................44 9.4 Effects of Reservoir Pressure Changes .............................................................................48 9.5 Refracture Treatment Design Considerations ....................................................................50 9.5.1 Fracture Initiation ...................................................................................................... 50 9.5.2 Fracture Extension ....................................................................................................50 9.5.3 Fracture Containment ...............................................................................................52 DOWELL CONFIDENTIAL



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9.5.4 Screenout ................................................................................................................. 52 9.5.5 Fracture-Fluid Recovery ........................................................................................... 52 Section 400 Figures Fig. 1. Basic fracture treatment design. ....................................................................................... 4 Fig. 2. Ideal fracture treatment design. ........................................................................................ 5 Fig. 3. Logic and associated activities of an adaptive procedure for fracture treatment design.. 7 Fig. 4. The modelization concept relevant to treatment design. .................................................. 9 Fig. 5. Fracturing fluid selection guide for a gas well. ................................................................ 14 Fig. 6. Fracturing fluid selection guide for an oil well. ................................................................ 15 Fig. 7. Effect on productivity index ratio (Jo, unfractured) of 5-in. damage around fracture. ...... 17 Fig. 8. Friction pressure drop of various tubing and casing sizes for 30 lbm/1000 gal delayed (dashed lines) and non-delayed (solid lines) borate fluids.............................................. 19 Fig. 9. Laminar and turbulent flow areas of viscoelastic fluids. .................................................. 19 Fig. 10. Fracture half-length requirements for a gas well........................................................... 23 Fig. 11. Retained permeability for linear fluids. .......................................................................... 24 Fig. 12. Retained permeability for borate-crosslinked fluids. ..................................................... 25 Fig. 13. Retained permeability for titanate-crosslinked fluids..................................................... 26 Fig. 14. Example of a production decline plot used to estimate recoverable reserves. ............. 42 Fig. 15. Example of a buildup data type-curve match. ............................................................... 43 Fig. 16. Example of a performance data type-curve match. ...................................................... 43 Fig. 17. Pressure contours around high-conductivity propped fractures.................................... 44 Fig. 18. The location of an infill well to improve recovery........................................................... 45 Fig. 19. Possible problem is fracture azimuth is unknown. ........................................................ 46 Fig. 20. Pressure contours around a short fracture or a fracture with low conductivity.............. 47 Fig. 21. Horizontal stress due to Poisson's ratio and pore pressure.......................................... 49 Fig. 22. Fracturing above a previous proppant-pack. ................................................................ 51 Section 400 Tables Table 1. Core data example....................................................................................................... 12 Table 2. Rheology selection guidelines (pump time less than four hours)................................ 20 Table 3. Rheology selection guidelines (pump time greater than four hours)........................... 21 Table 4. Poppant Selection Guide ............................................................................................. 27 Section 500 Treatment Execution 1 Job Planning .............................................................................................................................. 4 1.1 Minimum Job Planning......................................................................................................... 4 1.2 Minimum Service Quality and Safety Standards.................................................................. 5 1.3 Operational Considerations ................................................................................................. 5 1.3.1 Mixing Fracturing Fluids ............................................................................................. 5 1.3.2 Equipment .................................................................................................................. 6 2 Safety......................................................................................................................................... 7 3 Environment............................................................................................................................... 7 4 Quality........................................................................................................................................ 7 4.1 Location Quality Assurance ................................................................................................. 7 4.2 Fracturing Fluid Kit............................................................................................................... 8 DOWELL CONFIDENTIAL



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4.3 Testing References ..............................................................................................................8 5 Mixing and Metering of Additive Solutions..................................................................................9 5.1 Liquid Additives ....................................................................................................................9 5.1.1 Mixing Liquid-Additive Blends ...................................................................................11 5.2 Dry Additives in Solution.....................................................................................................11 5.2.1 Soluble Additives.......................................................................................................11 5.2.1.1 Mixing Solutions of Soluble Dry Additives ......................................................12 5.2.2 Insoluble Additives ....................................................................................................12 5.2.2.1 Mixing and Metering Fluid-Loss-Additive Slurries ..........................................13 5.3 Liquid-Additive Injection and Metering................................................................................13 5.3.1 Correcting the Additive Injection Rate to Proppant Concentration ............................14 5.3.2 Example Calculation for Mixing and Metering Additive Solutions .............................14 5.4 Water Solubilities of Various Dry Additives as a Function of Temperature ........................15 5.5 Methanol Solubilities of L10 as a Function of Temperature ...............................................17 5.6 Mixing and Metering Parameters for Various Solutions .....................................................17 6 Pressure Analysis During Fracturing Operations .....................................................................22 6.1 DSP Downhole Sensor Package (Real-Time Downhole Data Acquisition) ........................22 6.1.1 Fracturing Applications..............................................................................................23 6.1.2 System Components.................................................................................................23 6.1.2.1 Pressure and Temperature Gauges...............................................................24 6.1.2.2 Interface Module.............................................................................................25 6.2 Other Real-Time Data Acquisition Systems .......................................................................25 6.3 Downhole Memory Gauges ................................................................................................25 6.4 Additional Equations...........................................................................................................25 7 A Methodology For Improving Computed Bottomhole Pressures ............................................26 7.1 Recommendations..............................................................................................................28 7.2 Discussion ..........................................................................................................................28 7.2.1 Calibration Phase......................................................................................................29 7.2.1.1 Field Calibration .............................................................................................29 7.2.1.2 Office Calibration............................................................................................31 7.2.2 Application Phase .....................................................................................................32 7.3 Procedure A  Estimating the Closure Pressure and the Perforation/Near-Wellbore Friction Pressure .....................................................................................33 7.4 Procedure B  Estimating the Fluid Friction Pressure and the Net Pressure ...................34 7.5 Procedure C  Estimating the Fluid Friction of Slurry Using Rate Changes .....................35 7.6 Procedure D  Estimating the Slurry Friction Pressure Using the PPR Software .............36 7.7 Real-Time Application of Procedure A, Procedure B and Procedure C .............................37 7.8 Field Example.....................................................................................................................37 7.8.1 Net Pressures From Uncalibrated Field Data ...........................................................37 7.8.1.1 Estimating Closure Pressure and Perforation Friction....................................40 7.8.1.2 Measuring Pipe Friction of Non-Proppant Laden Fluids.................................42 7.8.1.3 Measuring Pipe Friction of Slurries ................................................................47 7.8.1.4 Office Calibration  Job Playback with PPR Software ..................................50



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7.8.1.5 PPR Hydrostatic Head Computation.............................................................. 60 8 Flowback Recommendations ................................................................................................... 63 8.1 Energized Fluids Flowback Procedure............................................................................... 63 8.2 Choke-Size Determination ................................................................................................. 64 8.2.1 Choke-Size Determination for Foam Flowback (Greater than 55-Quality) ............... 64 8.2.2 Choke-Size Determination for Energized (Nonfoamed) Fluids................................. 66 9 Contingency Plans ................................................................................................................... 69 9.1 Insufficient Pump Rate ....................................................................................................... 69 9.2 Proppant Delivery Failure .................................................................................................. 69 9.3 Equipment Malfunction ...................................................................................................... 69 9.4 Screenout........................................................................................................................... 69 Section 500 Figures Fig. 1. Compatability of common Dowell fracturing additives..................................................... 10 Fig. 2. The DSP system. ............................................................................................................ 24 Fig. 3. Schematic of treatment with systematic rate changes. ................................................... 30 Fig. 4. Friction multiplier as function of sand concentration. ...................................................... 31 Fig. 5. Treatment data for example well  uncalibrated. .......................................................... 38 Fig. 6. Net pressure plot for example well  uncalibrated......................................................... 39 Fig. 7. Procedure A Treatment data. ...................................................................................... 41 Fig. 8. Friction pressure of fresh water, 5 1/2-in. casing. ........................................................... 42 Fig. 9. Procedure B  Treatment data, YF540HT..................................................................... 43 Fig. 10. Field calibrated fluid friction curve, YF540HT. .............................................................. 45 Fig. 11. Treatment data during rate change, WF110. ................................................................ 46 Fig. 12. Field calibrated fluid friction curve, WF110 . ................................................................. 47 Fig. 13. Treatment data during first shut-down with proppant.................................................... 48 Fig. 14. Treatment data during second shut-down with proppant.............................................. 49 Fig. 15. Treatment data from end of proppant to shut-down...................................................... 51 Fig. 16. Treatment data for example well  calibrated. ............................................................ 53 Fig. 17. Net pressure plot for example well  calibrated........................................................... 54 Fig. 18. Treatment data during rate change, WF110  calibrated............................................ 55 Fig. 19. Procedure B  Treatment data, YF540HT  calibrated.............................................. 56 Fig. 20. Treatment data during first shut-down with proppant  calibrated. ............................. 57 Fig. 21. Treatment data during second shut-down with proppant  calibrated......................... 58 Fig. 22. Treatment data from end of proppant to shut-down  calibrated. ............................... 59 Fig. 23. Comparison of calculated hydrostatic pressures. ......................................................... 61 Fig. 24. Treatment data for example well  improved hydrostatic pressure. ............................ 62 Fig. 25. Determining QZ............................................................................................................. 65 Section 500 Tables Table 1. J218 ............................................................................................................................. 15 Table 2. J353 ............................................................................................................................. 15 Table 3. L10 ............................................................................................................................... 16 Table 4. M3 ................................................................................................................................ 16 Table 5. M117 ............................................................................................................................ 16 Table 6. L10 ............................................................................................................................... 17 DOWELL CONFIDENTIAL



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Table 7. Aqueous J218 Solutions...............................................................................................17 Table 8. L10/Methenol Solutions ................................................................................................18 Table 9. Aqueous L10 Solutions.................................................................................................18 Table 10. Aqueous J353 Solutions.............................................................................................19 Table 11. Aqueous M3 Solutions................................................................................................19 Table 12. Aqueous M117 Solutions............................................................................................20 Table 13. J84 and J418 Slurries.................................................................................................20 Table 14. YF100, YF200 Crosslink Activator Aqueous Solution Prepared with M2 ...................21 Table 15. YF100, YF200 Crosslink Activator Aqueous Solution Prepared with U28..................21 Table 16. YF100, YF200 Crosslink Activator Aqueous Solution Prepared with J465 or J474 Respectively...............................................................................................................21 Table 17. Aqueous Breaker Aid J466 Solution ...........................................................................22 Table 18. Summary of Procedures A through D.........................................................................28 Table 19. Pipe Friction as Function of Rate YF540HT, 5-1/2 in. Casing ....................................44 Table 20. Comparison of Actual and Estimated Pipe Friction Proppant Laden Fluid .................50 Table 21. Choke Coeffiecient versus Choke Size ......................................................................66 Table 22. Required Flowrate to Gas-Lift Water ..........................................................................67 Table 23. Flow of Water through Chokes ...................................................................................68 Section 600 Treatment Evaluation 1 Introductory Summary ................................................................................................................2 1.1 Treatment Evaluation Methodology......................................................................................2 1.2 Minimum Service Quality and Safety Standards ..................................................................3 2 Fracturing Pressure Analysis......................................................................................................3 2.1 Injection Pressure Interpretation...........................................................................................3 2.1.1 Nolte-Smith Plot ..........................................................................................................3 2.1.2 In-Situ Stress Requirements .......................................................................................7 2.1.3 References..................................................................................................................8 2.2 Pressure Decline Analysis ....................................................................................................8 2.2.1 References..................................................................................................................9 2.3 Fracture Height Prediction and Post-Treatment Measurements ..........................................9 2.3.1 Sonic Logs ..................................................................................................................9 2.3.2 References..................................................................................................................9 3 Treatment Performance Monitoring..........................................................................................10 3.1 Inverse Analysis of Treatment and Production Data Records ............................................10 3.1.1 Fracture Characterization Using the ZODIAC Software............................................11 3.1.1.1 Fracture Storage ............................................................................................12 3.1.1.2 Fracture Face Skin Damage ..........................................................................13 3.1.1.3 Variable Fracture Conductivity .......................................................................13 3.1.1.4 Reservoir Permeability Anisotropy .................................................................14 3.1.1.5 Finite Reservoirs ............................................................................................14 4 Production Evaluation...............................................................................................................22 4.1 References .........................................................................................................................23



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Section 600 Figures Fig. 1. Slope interpretation for the Nolte-Smith plot. .................................................................... 7 Fig. 2. Example of required stress contrasts................................................................................ 8 Fig. 3. High-conductivity fracture comparison. ............................................................................ 15 Fig. 4. Low-conductivity fracture comparison............................................................................. 15 Fig. 5. Fracture face skin damage, moderate-conductivity fracture. .......................................... 16 Fig. 6. Fracture face skin damage, finite-conductivity fracture................................................... 16 Fig. 7. Fracture face skin damage comparison, low-conducitivy fracture. ................................. 17 Fig. 8. Fracture skin damage comparison, low-conductivity fracture. ........................................ 17 Fig. 9. Finite-conductivity fracturecomparison, high average dimensionless conductivity. ........ 18 Fig. 10. Finite-conductivity comparison, moderate average fracture conductivity...................... 18 Fig. 11. Finite-conductivity comparison, uniform fracture conductivity 4000,000 md-ft.............. 19 Fig. 12. Finite-conductivity comparison, uniform fracture conductivity 4000,000 md-ft.............. 19 Fig. 13. Finite-conductivity comparison, uniform fracture conductivity 2000 md-ft..................... 20 Fig. 14. Finite-conductivity comparison, uniform fracture conductivity 2000 md-ft..................... 20 Fig. 15. ZODIAC software examples.......................................................................................... 21 Fig. 16. ZODIAC software examples.......................................................................................... 21 Fig. 17. ZODIAC software examples.......................................................................................... 22 Section 700 Techniques Section 700.1 DataFRAC Service 1 Introductory Summary................................................................................................................ 6 1.1 Closure Test......................................................................................................................... 7 1.1.1 Closure Test in a Permeable Zone ............................................................................. 7 1.1.2 Closure Test in a Nonpermeable Zone....................................................................... 9 1.2 Calibration Test.................................................................................................................... 9 1.3 Applications........................................................................................................................ 10 2 Design...................................................................................................................................... 11 2.1 Preparatory Engineering .................................................................................................... 11 2.1.1 Breakdown/Diversion Treatment .............................................................................. 11 2.1.2 Preliminary Fracture Design ..................................................................................... 11 2.1.3 Fracture Height......................................................................................................... 11 2.1.4 Wellbore Logging...................................................................................................... 12 2.1.4.1 Temperature and Gamma-Ray Logs ............................................................. 12 2.1.4.2 Fracture-Height Logs ..................................................................................... 13 2.1.5 Perforating ................................................................................................................ 13 2.1.5.1 Wellbore Restrictions ..................................................................................... 13 2.1.5.2 Perforation Phasing ....................................................................................... 14 2.1.5.3 Perforation Size ............................................................................................. 14 2.2 Closure Test....................................................................................................................... 15 2.2.1 Fluid Selection .......................................................................................................... 15 2.2.2 Injection Rates and Number of Steps ....................................................................... 15 2.2.3 Step Duration............................................................................................................ 15 2.2.4 Flow-Back Rate ........................................................................................................ 16 DOWELL CONFIDENTIAL



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2.3 Calibration Test ..................................................................................................................17 2.3.1 Fluid Selection...........................................................................................................17 2.3.1.1 Foam ..............................................................................................................17 2.3.2 Fluid Volume .............................................................................................................17 2.3.3 Fluid Break-Time.......................................................................................................18 2.3.4 Fluid-Loss Additives ..................................................................................................18 2.3.5 Duration of Pressure Decline ....................................................................................18 2.4 Special Considerations in the DataFRAC Design...............................................................18 2.4.1 The Influence of Wellbore Fluid ................................................................................18 2.4.2 Prepad.......................................................................................................................18 2.4.3 Closure Pressure less than Hydrostatic Pressure.....................................................19 2.4.4 Post-Job Wireline Surveys ........................................................................................19 2.5 Terminology........................................................................................................................19 2.5.1 Fracture Extension Pressure.....................................................................................19 2.5.2 Initial Shut-in Pressure ..............................................................................................19 2.5.3 Closure Pressure ......................................................................................................19 2.5.4 Rebound Pressure ....................................................................................................19 2.6 Equipment Requirements ...................................................................................................20 2.6.1 Monitoring Equipment ...............................................................................................20 2.6.2 Pumping Equipment..................................................................................................20 2.6.3 Pressure Measuring Equipment................................................................................20 2.6.3.1 Surface Measurement Methods .....................................................................20 2.6.3.2 Bottomhole Pressure Gauge Measurement ...................................................22 2.6.4 Treating Equipment...................................................................................................23 2.6.5 Flowback Equipment.................................................................................................23 2.6.5.1 Magnetic Flowmeters .....................................................................................23 2.6.5.2 Turbine Flowmeters........................................................................................23 2.6.5.3 Chokes and Gate Valves................................................................................23 3 Execution..................................................................................................................................24 3.1 Pre-Performance Guidelines ..............................................................................................24 3.2 Closure Test .......................................................................................................................27 3.2.1 Step-Rate Phase.......................................................................................................27 3.2.2 Flowback Phase........................................................................................................32 3.2.2.1 Flow Control ...................................................................................................32 3.2.2.2 Flowmeters.....................................................................................................34 3.2.3 Closure Test Modifications........................................................................................34 3.3 Calibration Test ..................................................................................................................35 3.3.1 Injection Phase..........................................................................................................35 3.3.2 Pressure-Decline Phase ...........................................................................................36 3.3.3 Contingency Plans ....................................................................................................36 4 Evaluation.................................................................................................................................36 4.1 Closure Test Analysis.........................................................................................................37 4.1.1 Step Rate  The BHP-Versus-Rate Plot..................................................................37 4.1.2 Flowback  The BHP-Versus-Time Plot ..................................................................37



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4.1.3 Confirmation of Closure Pressure............................................................................. 38 4.1.4 Rebound Pressure.................................................................................................... 40 4.2 Calibration Injection for Fracture Geometry ....................................................................... 40 4.2.1 Elastic Fracture Compliance..................................................................................... 41 4.2.2 Pressure During Pumping......................................................................................... 43 4.2.2.1 Fluid Flow and Pressure in Fracture .............................................................. 43 4.2.2.2 Nolte-Smith Plot and Evolution of Pressure During Pumping ........................ 45 4.2.3 Deviations from Ideal Geometry ............................................................................... 46 4.2.3.1 Height Growth ................................................................................................ 46 4.2.3.2 Fissures ......................................................................................................... 47 4.2.3.3 T-Shape Fracture........................................................................................... 48 4.2.4 Pressure Capacity .................................................................................................... 49 4.2.5 Near-Wellbore Restriction......................................................................................... 50 4.2.6 Fracturing Pressure Interpretation Summary ........................................................... 53 4.2.6.1 Example of Radial Fracture ........................................................................... 54 4.2.6.2 Simulation of Pressure During Pumping and Decline .................................... 54 4.3 Calibration Decline for Fluid-Loss Behavior ....................................................................... 56 4.3.1 Review of Decline Analysis....................................................................................... 56 4.3.2 Volume Function g.................................................................................................... 58 4.3.3 Fluid Efficiency.......................................................................................................... 59 4.3.4 Decline Function G ................................................................................................... 61 4.3.5 Non-Ideal Behavior ................................................................................................... 64 4.3.5.1 Change in Fracture Penetration After Shut-in................................................ 64 4.3.5.2 Height Growth ................................................................................................ 65 4.3.5.3 Pressure-Dependent Leakoff ......................................................................... 66 4.3.5.4 Spurt .............................................................................................................. 69 4.3.5.5 Closure Pressure Change.............................................................................. 69 4.3.5.6 Compressible Fluids ...................................................................................... 71 4.3.6 Fluid Efficiency Based on Pressure Analysis............................................................ 72 4.3.7 Decline-Analysis Procedure...................................................................................... 73 4.3.8 Steps to Correct Decline Analysis Using the FracCADE Software ........................... 75 4.3.8.1 The DataFRAC Software ............................................................................... 76 4.3.8.2 G-plot Interpretation by the DataFRAC Software........................................... 77 4.3.8.3 Modulus, Height or Fracture Toughness Calibrations.................................... 77 4.3.8.4 The β Ratio .................................................................................................... 78 4.3.9 Post Proppant Fracture Analysis .............................................................................. 80 4.3.10 References ............................................................................................................. 81 Section 700.1 Figures Fig. 1. The effect of proppant-pack damage and fracture length on fracture NPV. ..................... 6 Fig. 2. Fracture extension pressure (unequal time steps)............................................................ 7 Fig. 3. The typical closure test. .................................................................................................... 8 Fig. 4. The G-plot (idealized). .................................................................................................... 10 Fig. 5. Channel restriction at the wellbore.................................................................................. 13



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Fig. 6. The relation of perforation diameter and proppant concentration. ..................................14 Fig. 7. The effects of differing flowback rates. ............................................................................16 Fig. 8. The change in surface pressure during closure in deep, hot wells..................................21 Fig. 9. Hydrostatic head changes during closure. ......................................................................22 Fig. 10. The DataFRAC Service rig-up when pumping conductive fluids. ..................................25 Fig. 11. The DataFRAC Service rig-up when pumping nonconductive fluids. ............................26 Fig. 12. Friction pressure of water in the tubing and casing. ......................................................28 Fig. 13. Friction pressure of water in the annulus.......................................................................29 Fig. 14. Friction pressure of brine in the tubing and casing........................................................29 Fig. 15. Friction pressure of brine in the annulus. ......................................................................30 Fig. 16. Friction pressure of diesel in the tubing and casing. .....................................................30 Fig. 17. Friction pressure of diesel in the annulus. .....................................................................31 Fig. 18. Flow rate versus differential pressure in perforations....................................................31 Fig. 19. Flowback test (after Nolte, 1982/1994)..........................................................................38 Fig. 20. Effect of closure on BHP versus square root of t and G- plots. .....................................39 Fig. 21. Rebound pressure; lower bound of closure pressure....................................................40 Fig. 22. Analogy of a pressurized crack to a pre-loaded spring. ................................................42 Fig. 23. Evolution of fracture geometry and pressure during pumping.......................................45 Fig. 24. Pressure and width for height growth through barriers (after Nolte, 1989)...................46 Fig. 25. Pressure and width for opening natural fissures (after Nolte, 1989). ...........................47 Fig. 26. Pressure and width for T-shape fracture (after Nolte, 1989). .......................................48 Fig. 27. Definition of pressure capacity from in-situ stresses. ....................................................50 Fig. 28. Stress state within the entrance of deviated well or stress............................................51 Fig. 29. Mohr circle of deviated well or stress. ...........................................................................52 Fig. 30. Nolte-Smith plot of fracturing pressure. .........................................................................53 Fig. 31. Net pressure with radial fracture (after Smith et al. 1987). ...........................................54 Fig. 32. Measured and simulated net pressure: opening natural fissures (after Nolte, 1982). ..55 Fig. 33. Example of fracturing-related pressures (after Nolte, 1982)..........................................56 Fig. 34. Schematic for fracture area and time. ...........................................................................57 Fig. 35. Dimensionless volume function for fracture closure (after Nolte, 1986). ......................59 Fig. 36. Efficiency from closure time for no proppant, no spurt loss during pumping and other ideal assumptions given in Section 4.3.1 (after Nolte, 1986)...............................60 Fig. 37. Conceptual response of pressure decline versus Nolte time-function (after Castillo, 1987). ....................................................................................................62 Fig. 38. Penetration change during shut-in (after Nolte, 1990)...................................................65 Fig. 39. Diagnostic for height growth from decline data (after Nolte, 1990). ..............................66 Fig. 40. Diagnostic for stress sensitive fissures from injection and decline (after Nolte, 1990). 67 Fig. 41. Decline analysis for filtrate and reservoir control leakoff (after Nolte, 1993). ...............68 Fig. 42. Stress change during injection/shut-in for Cc (after Nolte et. al., 1993). ........................70 Fig. 43. Relative volume change of gas (after Nolte et. al., 1993).............................................72 Fig. 44. Decline analysis using “¾” rule (after Nolte, 1990)........................................................74 Fig. 45. Pressure and flow rate in fracture before and after shut-in (after Nolte, 1986). ...........79 Fig. 46. Diagnostic for closing on proppant from decline data (after Nolte, 1990).....................80



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Section 700.1 Tables Table 1. Approximate Choke Settings For Flowback Of Oil-Base Fluids (Sg = 0.7) .................. 33 Table 2. Approximate Choke Settings for Flowback of Water-Base Fluids (Sg = 1.0)............... 34 Table 3. Interpolated Values of α Over the Full Range of n....................................................... 58 Table 4. Values of Decline Function "G" .................................................................................... 63 Table 5. Correction Factors f c As Function Of ∆tD ...................................................................... 75 Section 700.2 Foam Fracturing 1 Introductory Summary................................................................................................................ 2 1.1 Foam Properties .................................................................................................................. 3 1.2 Foam Types ......................................................................................................................... 3 1.3 Foam Stability ...................................................................................................................... 4 1.4 Applications.......................................................................................................................... 4 2 Design........................................................................................................................................ 4 2.1 Choosing a Foam................................................................................................................. 4 2.1.1 The Liquid Phase........................................................................................................ 5 2.1.1.1 Linear Polymers ............................................................................................... 5 2.1.1.2 Crosslinked Polymers ...................................................................................... 6 2.1.1.3 Hydrocarbons and Alcohols ............................................................................. 7 2.1.2 The Gas Phase........................................................................................................... 7 2.1.2.1 Gas Behavior ................................................................................................... 9 2.1.2.2 Gas Solubility ................................................................................................. 10 2.1.3 Foaming Agent Selection.......................................................................................... 11 2.1.3.1 Material Compatibility with Foaming Agents .................................................. 11 2.2 Foam Rheology.................................................................................................................. 12 2.3 Fluid-Loss Properties ......................................................................................................... 13 2.3.1 Two-Phase Behavior of the Foam ............................................................................ 13 2.3.2 Wall-Building Effects................................................................................................. 13 2.4 Conductivity Damage ......................................................................................................... 14 2.5 Foam Quality...................................................................................................................... 16 2.6 Foam Texture..................................................................................................................... 19 2.7 Proppant Compensation .................................................................................................... 19 2.7.1 No Proppant Compensation ..................................................................................... 20 2.7.2 Constant Bottomhole Quality .................................................................................... 21 2.7.3 Decreasing Bottomhole Quality ................................................................................ 21 2.7.4 Constant Internal Phase ........................................................................................... 22 2.8 Friction Pressure................................................................................................................ 22 2.9 Yield Stress ........................................................................................................................ 23 2.10 Limitations of Application ................................................................................................. 23 2.11 Job Design ....................................................................................................................... 23 2.12 Calculations ..................................................................................................................... 23 2.12.1 Pressures and Rates .............................................................................................. 23 2.12.2 Equipment Requirements ....................................................................................... 25 2.12.3 Material Requirements ........................................................................................... 26



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3 Execution..................................................................................................................................26 3.1 Foam Generation ...............................................................................................................28 3.2 Material Balance.................................................................................................................30 Section 700.2 Figures Fig. 1. The effect of polymer loading on foam viscosity (50% quality foam).................................5 Fig. 2. The effect of various polymers on foam stability. ..............................................................6 Fig. 3. The effect of foam quality on viscosity (StableFOAM fluid). ............................................12 Fig. 4. Leakoff of a foam into the rock matrix. ............................................................................13 Fig. 5. Dimensionless polymer concentration factor...................................................................15 Fig. 6. Polymer concentration versus proppant-pack retained permeability...............................16 Fig. 7. Bubble arrangements for various foam-quality ranges....................................................17 Fig. 8. Proppant concentration limits in foam fluids. ...................................................................18 Fig. 9. The effect of proppant compensation methods on bottomhole foam quality. ..................20 Fig. 10. Friction through perforations. ........................................................................................25 Fig. 11. Schematic of foam fracturing treatment.........................................................................27 Fig. 12. Laminar and turbulent flow areas of foamed fluids........................................................29 Fig. 13. Foam generator.............................................................................................................29 Section 700.2 Tables Table 1. Summary of Foam Fracturing Fluids ..............................................................................3 Table 2. Comparison of Nitrogen and Carbon Dioxide.................................................................7 Table 3. Proppant-Pack Porosity of Sand and Intermediate-Strength Proppant ........................15 Section 700.3 RampGEL Service 1 Introductory Summary ................................................................................................................1 1.1 Application ............................................................................................................................2 2 Design ........................................................................................................................................3 2.1 Pad Fluid ..............................................................................................................................4 2.2 Fracturing Fluid Transporting Proppant................................................................................4 2.3 Computer-Aided Design .......................................................................................................4 3 EXECUTION...............................................................................................................................4 3.1 Batch Mixing .........................................................................................................................4 3.2 Continuous Mixing ................................................................................................................4 Section 700.3 Figures Fig. 1. Polymer concentration design scheme for the RampGEL software. .................................5 Section 700.4 CleanFRAC Service 1 Introductory Summary ................................................................................................................2 1.1 Applications ..........................................................................................................................2 2 Design ........................................................................................................................................2 2.1 Well Candidate Selection .....................................................................................................3 2.2 EB-Clean J475 Breaker........................................................................................................3 2.2.1 Mechanism of Breaker Release ..................................................................................5 2.3 Breaker Selection .................................................................................................................6 2.4 Job Design............................................................................................................................7 DOWELL CONFIDENTIAL



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2.4.1 CleanFRAC Service Design Methods......................................................................... 7 2.4.2 Summary of Software Features for the CleanFRAC Service Design.......................... 7 2.4.3 Design Procedure Using a Manual Calculation .......................................................... 8 2.4.4 Design Procedure Using the FracCADE Software Exclusively or in Combination With a Manual Calculation........................................................................................ 11 3 Execution ................................................................................................................................. 12 3.1 Metering the J475 Using the Auger-Type, Dry-Additive Feeder ........................................ 12 3.1.1 Procedure for Scheduling the J475 Using the Auger-Type Dry-Additive Feeder ..... 13 3.2 Metering the J218 as an Aqueous Solution ....................................................................... 14 3.2.1 Procedure for Calculating Mixing and Metering Parameters for J218 Solutions ...... 14 4 Examples ................................................................................................................................. 16 4.1 Example Design Using a Manual Calculation .................................................................... 16 4.2 Example Procedure for Scheduling the J475 Using the Auger-Type Dry-Additive Feeder........................................................................................................... 18 4.3 Example Procedure for Calculating Mixing and Metering Parameters for J218 Solutions ................................................................................................................... 19 Section 700.4 Figures Fig. 1. Effect of breaker concentration on retained viscosity for a borate-crosslinked guar fluid at 160°F (71°C).......................................................................................................... 4 Fig. 2. Effect of breaker concentration on retained proppant-pack permeability.......................... 5 Fig. 3. Effects of proppant concentration and porosity on postclosure polymer concentration. ... 9 Fig. 4. Influence of ammonium persulfate breaker on retained proppant-pack permeability for linear fracturing fluids................................................................................................... 9 Fig. 5. Influence of ammonium persulfate breaker on retained proppant-pack permeability for borate-crosslinked fracturing fluids. ........................................................................... 10 Fig. 6. Influence of ammonium persulfate breaker on retained proppant-pack permeability for organometallic-crosslinked fracturing fluids............................................................... 10 Section 700.4 Tables Table 1. J475 Release Levels (no closure stress) ....................................................................... 6 Table 2. Proppant-Pack Porosity of Sand and Intermediate-Strength Proppant.......................... 8 Table 3. J475 Metering Rates Auger-Type, Dry-Additive Feeder .............................................. 12 Section 700.5 Fracture-Height-Containment Services 1 Introductory Summary................................................................................................................ 2 1.1 Fracture Height Prediction ................................................................................................... 3 1.2 Fracture Penetration ............................................................................................................ 3 1.3 Fracture Evolution................................................................................................................ 4 1.4 Fracture Height-Growth and Containment ........................................................................... 7 1.5 Fracture-Height-Containment Services................................................................................ 9 2 DIVERTAFRAC Service........................................................................................................... 10 2.1 Discussion.......................................................................................................................... 10 2.2 Design Methodology .......................................................................................................... 11



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2.2.1 Design Example ........................................................................................................13 2.3 Execution Methodology ......................................................................................................15 2.4 DIVERTAFRAC Fluid Using Water Control Agent S41 as a Diverting Material..................15 2.4.1 Spacers .....................................................................................................................15 2.4.2 Dilution with Sand .....................................................................................................15 2.4.3 Additional Information ...............................................................................................15 3 INVERTAFRAC Service ...........................................................................................................16 3.1 Design Methodology...........................................................................................................16 3.2 Execution Methodology ......................................................................................................17 3.2.1 Field Mixing Procedures............................................................................................18 3.2.2 Additional Mixing Techniques ...................................................................................19 4 Computer-Aided Design ...........................................................................................................20 4.1 Additional Computer-Aided Job Design Information...........................................................22 Section 700.5 Figures Fig. 1. First phase of evolution. ....................................................................................................4 Fig. 2. Illustration of fracture growth. ............................................................................................5 Fig. 3. Linear plot of pressure.......................................................................................................6 Fig. 4. Log-Log plot of net pressure. ............................................................................................6 Fig. 5. Pressure and width for growth through barriers. ...............................................................7 Fig. 6. Height control and conventional treatment for an offset well.............................................8 Fig. 7. Principles of fracture-height-containment techniques........................................................9 Fig. 8. J423 rise rate versus fluid viscosity (static conditions). ...................................................17 Fig. 9. J423 flow rate versus area. .............................................................................................19 Section 700.5 Tables Table 1. J423 Addition Rate .......................................................................................................18 Section 700.6 Breakdown Techniques 1 Introductory Summary ................................................................................................................2 2 Applications ................................................................................................................................3 3 Treatment Design .......................................................................................................................3 3.1 Fracture Gradient .................................................................................................................5 3.2 Fluid Selection ......................................................................................................................5 3.2.1 Solvent Selection Guidelines.......................................................................................6 3.3 Types of Formation Damage ................................................................................................8 3.4 Fluid-Loss Control ..............................................................................................................13 3.5 Fluid Volumes.....................................................................................................................13 3.6 Fluid Diversion....................................................................................................................14 3.6.1 Ball Sealers ...............................................................................................................14 3.6.2 Chemical Diverting Agents ........................................................................................15 4 Execution..................................................................................................................................16 5 Evaluation.................................................................................................................................17 6 Examples..................................................................................................................................18 6.1 Example No. 1 ....................................................................................................................18



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6.2 Example No. 2 ................................................................................................................... 20 Section 700.6 Figures Fig. 1. Ball catcher. .................................................................................................................... 17 Fig. 2. Friction loss of 15% HCl in 2.875 in. tubing. ................................................................... 22 Section 700.6 Tables Table 1. Breakdown Design Methodology ................................................................................... 4 Table 2. The Dowell Solvent Formulations Most Commonly Used for Breakdown Fluids (The Stimulation Materials  Acidizing Manual provides information for these systems)...... 7 Table 3. Summary of Formation Damage.................................................................................... 9 Section 700.7 Diverting Techniques 1 Introductory Summary................................................................................................................ 2 2 Application ................................................................................................................................. 4 2.1 Ball Sealers .......................................................................................................................... 5 2.1.1 Buoyant Ball Sealers .................................................................................................. 5 2.1.2 Conventional Ball Sealers........................................................................................... 8 2.1.3 Temperature and Pressure Effects........................................................................... 13 2.1.4 Effects of Various Fluids ........................................................................................... 13 2.2 Limited Entry ...................................................................................................................... 14 2.2.1 Perforation Erosion ................................................................................................... 18 2.2.2 Contributing Factors ................................................................................................. 19 2.2.2.1 Casing Size.................................................................................................... 19 2.2.2.2 Number and Size of Perforations................................................................... 19 2.2.2.3 Differences in Fracturing Pressures............................................................... 21 2.2.2.4 Pressure Limitations ...................................................................................... 21 2.2.2.5 Hydraulic Horsepower Requirements ............................................................ 21 2.2.2.6 Perforation Friction Pressure ......................................................................... 21 2.2.2.7 Breakdown Technique ................................................................................... 22 2.2.2.8 Determination of Formation Fracturing Pressure........................................... 22 2.2.3 Design ...................................................................................................................... 22 2.3 Single-Point Entry .............................................................................................................. 33 2.4 Plugback (Pine Island) Technique ..................................................................................... 34 2.5 Slurried Solids .................................................................................................................... 36 2.6 Viscous Fluids .................................................................................................................... 37 2.7 Baffles and Balls ................................................................................................................ 38 2.8 Bridge Plugs....................................................................................................................... 40 Section 700.7 Figures Fig. 1. Rising velocity of 7/8-in. OD buoyant ball sealers............................................................. 7 Fig. 2. This graph provides information necessary for calculating the injection rate to “balance” buoyant balls in different sizes of pipe. ............................................................. 7 Fig. 3. Example printout of the PERFBALL ball-sealer-performance computer software. ........... 9 Fig. 4. This graph contrasts the pump rate versus fluid velocity in different sizes of pipes........ 12



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Fig. 5. This graph contrasts the pump rate versus fluid velocity in different sizes of perforations. ....................................................................................................................12 Fig. 6. Core selection guide for temperature and pressure. .......................................................13 Fig. 7. Injection rate increases thus friction pressure increases.................................................15 Fig. 8. Nomograph for determining friction through a perforation...............................................16 Fig. 9. Reference to determine the injection rate per perforation using fresh water...................17 Fig. 10. Higher density fluids exhibit higher perforation friction pressures. ................................18 Fig. 11. Change in perforation friction versus perforation coefficient. ........................................20 Fig. 12. Gamma ray-sonic log. ...................................................................................................23 Fig. 13. Friction of WF140 in 4 1/2 and 5 1/2 in. pipe.................................................................25 Fig. 14. Plugback Pine Island technique. ...................................................................................34 Fig. 15. Two-stage fracturing procedure, using baffle and ball technique. .................................39 Section 700.7 Tables Table 1. Perforation Size versus Ball-Sealer Core Size ...............................................................5 Table 2. Example for Selecting a Perforation Schedule for Multiple Zones Having Different Bottomhole Fracturing Pressures .................................................................................32 Table 3. Diverting Agents ...........................................................................................................36 Section 700.8 CleanFLOW Technology 1 Introductory Summary ................................................................................................................1 2 The CleanFLOW System............................................................................................................2 2.1 Optimized Breaker Composition...........................................................................................2 2.2 J495 CleanFLOW Additive ...................................................................................................3 2.3 CleanFLOW Application .......................................................................................................4 2.3.1 Temperature ...............................................................................................................4 2.3.2 J495 Concentrations ...................................................................................................4 2.3.3 Breaker Interactions ....................................................................................................4 2.3.4 Material Handling ........................................................................................................5 2.3.5 Field Results ...............................................................................................................5 3 Conductivity Measurements .......................................................................................................5 3.1 Polymer Concentration .........................................................................................................6 3.2 Pressure-Drop Measurements .............................................................................................7 3.3 Other Parameters .................................................................................................................7 3.4 Summary ..............................................................................................................................7 Section 700.8 Tables Table 1. Breaker Schedule Design Example ................................................................................3 Section 700.9 PropNET Technology 1 Introductory Summary ................................................................................................................2 2 Design ........................................................................................................................................6 2.1 Flowback Stability.................................................................................................................6 2.2 Two-Phase Flow.................................................................................................................10 2.3 Effective Proppant-Pack Stress Cycling .............................................................................11 2.4 Effect of Fluid Viscosity on Proppant-Pack Stability ...........................................................12 2.5 Proppant-Pack Permeability ...............................................................................................13 DOWELL CONFIDENTIAL



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2.6 PropNET Lifetime............................................................................................................... 19 2.7 Stability in Acids ................................................................................................................. 21 2.8 Effect on Proppant Settling ................................................................................................ 21 2.9 Fiber Breakage During Treatments.................................................................................... 23 2.10 Case Histories.................................................................................................................. 25 3 PropNET References ............................................................................................................... 29 4 Appendix A - Flow Test Apparatus........................................................................................... 30 4.1 Fracture Geometry............................................................................................................. 30 4.2 Perforation Geometry......................................................................................................... 30 4.3 Tube Geometry .................................................................................................................. 30 Section 700.9 Figures Fig. 1. A molehole formed in a proppant pack of 20/40-mesh sand (FracTech test), viewed from the 5.25 in. by 5.25 in. face. ....................................................................... 10 Fig. 2. Pressure at failure versus nitrogen flow concentration. .................................................. 11 Fig. 3. Effect of fluid viscosity on pack stability. ......................................................................... 13 Fig. 4. The effect of closure stress on proppant-pack permeability with and without J500. ....... 18 Fig. 5. The effect of J501 concentration on the permeability of 16/20 Carbolite. (Fluid: corn syrup.) .......................................................................................................... 19 Fig. 6. Predicted proppant-pack strength with aging time for J500. ........................................... 20 Fig. 7a. Proppant settling in WF150 fluid. .................................................................................. 22 Fig. 7b. Proppant settling in WF150 fluid. Fig. 8. The effect of J501 on proppant settling in WF175 fluid under dynamic conditions. ........ 23 Fig. 9. Resin-coated proppant containing PropNET fibers after pumping and removal from a well....................................................................................................................... 24 Fig. 10. PropNET fibers after pumping, removal from a well and cleaning to remove oil. ........ 25 Fig. 11. South Texas well, 15% J501 tail-in. .............................................................................. 26 Fig. 12. Fluid returns, South Texas offset wells. ........................................................................ 27 Fig. 13. Polymer returns, offset wells. ........................................................................................ 28 Fig. 14. Fracture geometry test apparatus................................................................................. 31 Fig. 15. Perforation geometry test apparatus............................................................................. 32 Fig. 16. Tube geometry test apparatus. ..................................................................................... 32 Section 700.9 Tables Table 1. Summary of Flowback and Production Rates for the Highest-Rate PropNET Wells to date................................................................................................................... 5 Table 2. Resistance to Flowback in the Fracture Geometry ........................................................ 7 Table 3. Resistance to Flowback in the Perforation Geometry .................................................... 8 Table 4. Failure of Proppant Packs Containing J501 in Cyclic Loading..................................... 12 Table 5. Permeabilities of Various ISP and Curable RCP Proppant Packs ............................... 14 Table 6. Permeabilities of Various Sand and Curable RCP Packs ............................................ 14 Table 7. Permeabilities of Precured RCP Packs........................................................................ 15 Table 8. Permeabilities of 20/40-Mesh Ottawa Sand Packs ...................................................... 15 Table 9. Permeabilities of 12/20-Mesh Ottawa Sand Packs ...................................................... 16 Table 10. Permeabilities of 16/20-Mesh Carbolite Packs .......................................................... 17 Table 11. Permeabilities of 20/40-Mesh Interprop Plus Packs .................................................. 17 DOWELL CONFIDENTIAL



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Section 700.9 Supplement 1 Wellbore Cleanup .......................................................................................................................1 2 Flowback, Swabbing...................................................................................................................1 3 Shut-in, Clean-up, and Production Rates ...................................................................................2 4 Appendix.....................................................................................................................................4 Section 700.9 Supplement Figures Fig. 1. Maximum swab-cable speed vs casing ID and number of perforations. ...........................4 Section 700.9 Supplement Tables Table 1. Maximum Worldwide PropNET Flowback and Production Rates...................................5 Section 800 HyPerSTIM Service 1 Introduction.................................................................................................................................4 1.1 Objectives.............................................................................................................................4 1.2 Applications ..........................................................................................................................5 1.3 Limitations of Application......................................................................................................6 2 Design ........................................................................................................................................6 2.1 Candidate Selection .............................................................................................................7 2.2 Characterization of Formation Mechanical Properties..........................................................9 2.3 Design Basis.......................................................................................................................10 2.4 Fluid Selection ....................................................................................................................15 2.4.1 Fluid-Loss Control .....................................................................................................16 2.4.1.1 Pressure Effects .............................................................................................18 2.4.1.2 Temperature Effects.......................................................................................19 2.4.1.3 Effects of Fluid Viscosity and Polymer ...........................................................20 2.4.1.4 Effects of Fluid-Loss Additives .......................................................................21 2.4.1.5 Fluid Selection and Fluid-Loss Control...........................................................21 2.4.2 The DataFRAC Service Application ..........................................................................21 2.5 Proppant Selection and Fracture Conductivity ...................................................................22 2.5.1 Embedment...............................................................................................................23 2.5.1.1 Spalling...........................................................................................................25 2.5.1.2 Impact on Permeability...................................................................................26 2.5.2 Non-Darcy Flow ........................................................................................................27 2.5.2.1 Determination of the Inertial Flow Coefficient.................................................28 2.5.2.2 Non-Darcy Flow Correction of Dimensionless Fracture Conductivity.............32 2.5.2.3 Proppant Selection Using Manual Calculation ...............................................33 2.5.2.4 Computer-Aided Proppant Selection ..............................................................35 2.5.2.5 Proppant Selection Using the FracCADE Software........................................37 2.5.2.6 Proppant Selection Summary.........................................................................37 2.5.3 Formation Sand and Fines........................................................................................37 2.5.3.1 Control of Formation Fines and Sand ............................................................40 2.5.4 Proppant Flowback Control.......................................................................................40 2.6 FracCADE Software ...........................................................................................................44 2.6.1 FracNPV and QUICK Modules..................................................................................44 2.6.2 The FORECAST Module...........................................................................................47 DOWELL CONFIDENTIAL



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2.6.3 The PLACEMENT II Simulator ................................................................................. 49 3 Execution ................................................................................................................................. 54 3.1 Batch-Mix Operations ........................................................................................................ 54 3.2 Continuous-Mix Operations ............................................................................................... 55 4 Evaluation ................................................................................................................................ 55 4.1 Prats’ Correlation ............................................................................................................... 56 4.2 Modified McGuire-Sikora Correlation ................................................................................. 56 5 Fluid-Loss Data........................................................................................................................ 64 5.1 WF120 (J164) Containing 25 lbm J478/1000 gal and 25 lbm J418/1000 gal BHST=150°F (66°C), Pressure=1000 psi .......................................................................... 64 5.2 WF160 (J164) Without Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 65 5.3 WF160 (J164) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 66 5.4 WF110 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure- 1000 psi ............................................................................................................ 67 5.5 WF120 (J424) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 68 5.6 WF130 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 69 5.7 WF140 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 70 5.8 WF160 (J424) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ............................................................................................................. 71 5.9 YF140 (J424)  BHST=150°F (66°C), Pressure-1000 psi................................................ 72 5.10 YF140 (J424)  BHST=150°F (66°C), Pressure-1000 psi.............................................. 73 5.11 YF140 (J424)  BHST=175°F (79°C), Pressure-1000 psi.............................................. 74 5.12 YF140HTD (J424)  BHST=200°F (93°C), Pressure-1000 psi ...................................... 75 5.13 YF140HTD (J424)  BHST=250°F (121°C), Pressure-1000 psi .................................... 76 Section 800 Figures Fig. 1. Production rate sensitivity to skin...................................................................................... 8 Fig. 2. IPR curve sensitivity to skin. ............................................................................................. 8 Fig. 3. The effect on shifting an 80% damage collar. ................................................................. 11 Fig. 4. Productivity-increase curves. .......................................................................................... 12 Fig. 5. Effective wellbore radius for pseudo-radial flow.............................................................. 14 Fig. 6. Fluid-loss data for YF140................................................................................................ 17 Fig. 7. Pressure gradient through a sand pack versus gas flow rate, darcy and non-darcy flow.27 Fig. 8. Total pressure drawdown versus transit time, sanding prediction. ................................. 39 Fig. 9. Curable resin-coated proppant compressive strength required to prevent flowback. .... 44 Fig. 10. Proppant Editor. ............................................................................................................ 45 Fig. 11. FracNPV Input. ............................................................................................................. 45 Fig. 12. Equivalent wellbore radius and pseudo-skin................................................................. 47 Fig. 13. PRODUCTION FORECAST input................................................................................. 47 Fig. 14. Production simulation, non-darcy flow. ......................................................................... 49 DOWELL CONFIDENTIAL



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Fig. 15. ROCK input. ..................................................................................................................50 Fig. 16. ZONES — layer data input. ...........................................................................................51 Fig. 17. PLACEMENT SIMULATOR — conventional design, 20/40-mesh sand, 1400 gal pad. ................................................................................................................57 Fig. 18. PLACEMENT OUTPUT — conventional design, 20/40-mesh sand. .............................57 Fig. 19. PLACEMENT SIMULATOR — P3D tip-screenout design, 20/40-mesh sand, 1600 gal pad. ................................................................................................................58 Fig. 20. PLACEMENT OUTPUT — P3D tip-screenout design, 20/40-mesh sand. ....................58 Fig. 21. PLACEMENT SIMULATOR — conventional design, 12/20-mesh sand, 1800 gal pad.59 Fig. 22. PLACEMENT OUTPUT — conventional design, 12/20- mesh sand. ............................59 Fig. 23. PLACEMENT SIMULATOR — P3D tip-screenout design, 12/20-mesh sand, 3500 gal pad. ................................................................................................................60 Fig. 24. PLACEMENT OUTPUT — P3D tip-screenout design, 12/20-mesh sand. ...................60 Fig. 25. Stage front propogation. ................................................................................................61 Fig. 26. Fracture height profile ...................................................................................................61 Fig. 27. Wellbore fracture width profile. ......................................................................................62 Fig. 28. Fracture height growth history. ...................................................................................... 62 Fig. 29. Fracturing (net) pressure profile. ................................................................................... 63 Section 800 Tables Table 1. Water Viscosity at Temperature ...................................................................................20 Table 2. Dry Proppant Pack Intertial Coefficient Factors............................................................31 Table 3. Proppant Selection With Embedment and Non-Darcy Flow .........................................35 Section 900 Acid Fracturing 1 Principles of Acid Fracturing.......................................................................................................2 1.1 Fracture Length and Fracture Conductivity ..........................................................................4 1.2 Factors Affecting Acid Behavior in Carbonate Reservoirs....................................................6 1.2.1 Acid Type, Strength, and Volume ...............................................................................6 1.2.2 Acid Leakoff ................................................................................................................9 1.2.3 Controlling Acid Leakoff ............................................................................................14 1.2.4 Acid Reaction Rate ...................................................................................................15 1.2.5 Acid Spending Time ..................................................................................................17 2 Treatment Design Fundamentals for Acid Fracturing...............................................................18 2.1 Achieving Acid Penetration.................................................................................................19 2.2 When Acid Fracture Length Should be Maximum ..............................................................19 2.3 When Acid Fracture Length Should be Limited ..................................................................19 2.4 Maximizing The Injection Rate ...........................................................................................20



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2.5 Optimizing Conductivity and Etched Fracture Length ........................................................ 20 2.6 Effective Acid Concentration .............................................................................................. 21 2.7 Selecting Fluids for Deeper Acid Penetration .................................................................... 22 2.8 Determination of Leakoff Coefficients ................................................................................ 24 2.8.1 Methodology ............................................................................................................. 24 2.8.2 Example Calculation ................................................................................................. 29 2.8.3 Notes ........................................................................................................................ 31 2.9 Cooldown ........................................................................................................................... 31 2.10 Retarded Acid .................................................................................................................. 33 2.11 Viscous Fingering ............................................................................................................ 36 2.12 Summary of Treatment Design Fundamentals for Acid Fracturing .................................. 37 Section 900 Figures Fig. 1. Conductivity ratio versus increase in folds. ....................................................................... 5 Fig. 2. Acid spending in carbonate rock. ...................................................................................... 8 Fig. 3. Casting of a typical wormhole pattern in limestone......................................................... 12 Fig. 4. Test results, carbonate cores and wormholes. ............................................................... 12 Fig. 5. Test results, carbonate cores and wormholes. ............................................................... 13 Fig. 6. Test results, carbonate cores and wormholes. ............................................................... 13 Fig. 7. Viscosity of fresh water versus temperature. .................................................................. 25 Fig. 8. Spending time versus HCl concentration at static conditions. ........................................ 35 Fig. 9. Temperature versus retardation factor at dynamic test conditions. ................................ 36 Section 900 Tables Table 1. Factors that Influence Fracture Conductivity and Fracture Penetration when Acid Fracturing a Carbonate Reservoir .................................................................................. 6 Table 2. Acid Types and Strengths Common to Oilfield Operations............................................ 9 Table 3. Total Minimum Leakoff Coefficients versus Temperature and Permeability ................ 26 Table 4. Scale Factor Base Values (SFb)................................................................................... 27 Table 5. Scale Factor Corrections ............................................................................................. 28 Table 6. Retardation Factor Selection Guidelines...................................................................... 34 Section 1000 Horizontal Wells 1 Introductory Summary................................................................................................................ 4 1.1 Candidate Reservoirs for Horizontal Wells .......................................................................... 4 1.1.1 Naturally-Fractured Reservoirs................................................................................... 4 1.1.2 Matrix-Permeability Reservoirs................................................................................... 4 1.1.2.1 Vertical Permeability ........................................................................................ 5 1.1.2.2 Skin Damage ................................................................................................... 6 1.2 Fracture Performance and Wellbore Orientation ................................................................. 7 2 Fracture Orientation ................................................................................................................... 8 3 Fractured Horizontal Well Performance ................................................................................... 10 3.1 Longitudinal Fracture ......................................................................................................... 10 3.2 Orthogonal Fractures ......................................................................................................... 11 3.3 Choke Skin Effect............................................................................................................... 13 3.3.1 Fracture Reorientation — Choke Effect.................................................................... 14 DOWELL CONFIDENTIAL



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3.4 Coning Effects ....................................................................................................................15 3.4.1 Comparison of Fractured and Nonfractured Reservoir .............................................15 3.4.2 Effect of the Distance From the Fracture to the Water Zone ....................................15 4 Rock Mechanical Properties.....................................................................................................17 4.1 Openhole Wellbore Stability ...............................................................................................17 4.2 Shear Failure ......................................................................................................................18 4.3 Tensile Failure ....................................................................................................................18 4.4 Matrix Collapse...................................................................................................................18 4.5 Cased-Hole Wellbore Stability ............................................................................................19 4.6 Stress and Deformation Analysis .......................................................................................20 5 Fracture Initiation And Propagation ..........................................................................................20 5.1 Initiation Pressure...............................................................................................................20 5.2 Fracture Initiation................................................................................................................21 5.3 Fracture Propagation..........................................................................................................23 5.4 Longitudinal Fractures ........................................................................................................23 5.5 Angled Fractures ................................................................................................................24 5.6 Transverse Fractures .........................................................................................................25 5.7 Controlling Fracture Reorientation......................................................................................26 6 Perforating ................................................................................................................................27 7 Treatment Design .....................................................................................................................29 7.1 Net Present Value Analysis ................................................................................................29 7.1.1 Calculating the NPV of Orthogonal Fractures ...........................................................29 7.1.2 Horizontal Well Production Prediction .......................................................................31 7.2 Fracture Height...................................................................................................................34 7.3 Fracture Orientation ...........................................................................................................34 7.4 Fracture Length and Conductivity.......................................................................................34 7.5 Pump Rate..........................................................................................................................34 7.6 Fracturing Fluid Selection...................................................................................................34 7.7 Proppant Selection .............................................................................................................35 7.7.1 Mesh Range..............................................................................................................35 7.7.2 Proppant Type...........................................................................................................35 7.7.3 Proppant Concentration ............................................................................................35 8 Execution..................................................................................................................................35 8.1 Perforating ..........................................................................................................................35 8.1.1 When to Perforate .....................................................................................................36 8.2 Wellbore Isolation Between Fractures................................................................................36 8.2.1 Isolation Using Mechanical Tools..............................................................................37 8.2.2 Isolation Using Proppant Plugs .................................................................................37 8.2.2.1 Intentional Screenout .....................................................................................37 8.2.2.2 Multidensity/Multimesh Proppant ...................................................................38 8.2.3 Isolation Using Viscous Plugs ...................................................................................38 8.2.4 Wellbore Isolation in an Openhole Completion .........................................................39 8.3 Flowback ............................................................................................................................39 9 Overview of the Horizontal Well Treatment-Design Procedure ................................................40 10 Case History 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Section 1000 Figures Fig. 1. Productivity index ratios for horizontal versus vertical wells. ............................................ 6 Fig. 2. A longitudinal fracture. ...................................................................................................... 8 Fig. 3. An orthogonal fracture. ..................................................................................................... 9 Fig. 4. A fracture propagating at an angle to the wellbore. .......................................................... 9 Fig. 5. Productivity index ratios of vertical well/vertical fracture and horizontal well with a longitudinal fracture......................................................................................................... 10 Fig. 6. NPV analysis for a vertical well. ...................................................................................... 12 Fig. 7. NPV analysis for one orthogonal fracture. ...................................................................... 12 Fig. 8. Water breakthrough time versus the position of the fracture with respect to the oil/water contact. ....................................................................................................... 16 Fig. 9. Production rate versus water-cut. ................................................................................... 16 Fig. 10. Fracture conductivity versus water-cut. ........................................................................ 17 Fig. 11. Mohr failure envelope for matrix collapse. .................................................................... 18 Fig. 12. Stress distribution around a perforation. ....................................................................... 20 Fig. 13. Initiation pressure as a function of α and the borehole inclination. ............................... 21 Fig. 14. Horizontal well configuration in the in-situ stress field................................................... 21 Fig. 15. Initiation points and fracture orientation on the borehole. ............................................. 22 Fig. 16. Fracture initiation pressure. .......................................................................................... 22 Fig. 17. The effect of distance between collinear fractures on maximum fracture width............ 24 Fig. 18. Fracture rotation angle versus spacing......................................................................... 25 Fig. 19. Width and excess pressure as a function of spacing for parallel, transverse and radial fractures........................................................................................................ 26 Fig. 20. Radius of fracture reorientation as a function of the ratio between the maximum and minimum horizontal stresses. ................................................................................. 27 Fig. 21. Critical distance between perforation versus well orientation. ...................................... 28 Fig. 22. Single phase flow .......................................................................................................... 33 Fig. 23. NPV analysis of the number of orthogonal fractures..................................................... 42 Fig. 24. Actual versus predicted fluid production. ...................................................................... 43 Section 1000 Tables Table 1. Performance Comparison Of Vertical And Horizontal Wells With Fractures................ 13 Table 2. Pseudoskin Factor Correlation Contstants................................................................... 32 Table 3. Overview of Fracture Treatment Design Considerations for Horizontal Wells ............. 40 Table 4. Stress Measurement Techniques ................................................................................ 41 Section 1100 Appendix A - Fracturing Design-Execution-Evaluation Example 1 Well Data ................................................................................................................................... 3 2 Reservoir Evaluation .................................................................................................................. 3 3 DataFRAC Service................................................................................................................... 11 4 Treatment Design .................................................................................................................... 22 4.1 Fracturing Fluid Selection .................................................................................................. 22 4.2 Proppant Selection............................................................................................................. 22 4.3 Fracture Length Optimization............................................................................................. 24 4.4 In-Situ Stress Data ............................................................................................................. 27 4.5 Approximate Pumping Schedule........................................................................................ 28 DOWELL CONFIDENTIAL



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4.6 Placement Design ..............................................................................................................32 4.7 Production Forecast ...........................................................................................................35 5 Treatment Execution ................................................................................................................40 6 Treatment Evaluation ...............................................................................................................42 7 Post-Fracture Well-Test Analysis .............................................................................................44 Section 1100 Figures Fig. 1. Review output for all transients. ........................................................................................5 Fig. 2. Diagnostic plot - Transient 1..............................................................................................7 Fig. 3. Wellbore storage - Transient 1. .........................................................................................8 Fig. 4. Horner plot - Transient 1. ..................................................................................................9 Fig. 5. Multi-rate type curve and derivative match......................................................................10 Fig. 6. Verification plot. ...............................................................................................................10 Fig. 7. Production decline. ..........................................................................................................11 Fig. 8. NODAL analysis. .............................................................................................................12 Fig. 9. DataFRAC job record. .....................................................................................................13 Fig. 10. Step-rate test. ................................................................................................................13 Fig. 11. DataFRAC job record (replotted)...................................................................................14 Fig. 12. Pressure analysis ..........................................................................................................14 Fig. 13. Closure pressure estimation.......................................................................................... 16 Fig. 14. “G” plot. .........................................................................................................................18 Fig. 15. Net Present Value. ........................................................................................................24 Fig. 16. Cumulative production...................................................................................................25 Fig. 17. Fracture height-growth history....................................................................................... 35 Fig. 18. Wellbore fracture width profile. ......................................................................................35 Fig. 19. Fracture height profile. ..................................................................................................36 Fig. 20. Production decline. ........................................................................................................40 Fig. 21. Cumulative production...................................................................................................40 Fig. 22. Post-fracture IPR curves (NODAL analysis)..................................................................41 Fig. 23. Job record. ....................................................................................................................42 Fig. 24. Pressure analysis (Nolte-Smith plot). ............................................................................43 Fig. 25. Job record. ....................................................................................................................44 Fig. 26. Pressure analysis. .........................................................................................................44 Fig. 27. Linear flow regime. ........................................................................................................47 Fig. 28. Vertical fracture, linear flow - Transient 1. .....................................................................48 Fig. 29. Multi-rate type curve and derivative match....................................................................48 Section 1100 Tables Table 1. Buildup Test....................................................................................................................5 Table 2. DataFRAC Pressure Record ........................................................................................14 Table 3. Pressure Decline Analysis ............................................................................................18 Table 4. Input Data for FracNPV ................................................................................................25 Table 5. Output From the Inverse Module..................................................................................28 Table 6. Output of the PLACEMENT Simulator..........................................................................33 Table 7. Input Data for MLPP Production-Control Input .............................................................36 Table 8. Input Data for MLPP Production-Control Input .............................................................36 DOWELL CONFIDENTIAL



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Table 9. Input Data for MLPP Production-Control Input............................................................. 37 Table 10. MLPP Output ............................................................................................................. 38 Table 11. Fracture Geometry..................................................................................................... 44 Table 12. Build-up Pressure Response ..................................................................................... 45 Section 1200 Appendix B - Fracturing Fluids 1 Introductory Summary................................................................................................................ 3 2 Water-Base Fluids ..................................................................................................................... 4 2.1 Polymers .............................................................................................................................. 4 2.1.1 Guar Gum................................................................................................................... 4 2.1.2 Hydroxypropylguar ..................................................................................................... 5 2.1.3 Hydroxyethylcellulose ................................................................................................. 6 2.1.4 Xanthan ...................................................................................................................... 7 2.1.5 Carboxymethylhydroxypropylguar .............................................................................. 8 2.2 Crosslinkers ......................................................................................................................... 8 2.2.1 Borate Crosslinker ...................................................................................................... 8 2.2.2 Organometallic Crosslinkers....................................................................................... 9 2.2.3 Crosslink Rate ............................................................................................................ 9 2.2.3.1 YF100 and YF200 Fluids ............................................................................... 10 2.2.3.2 YF300 and YF400 Fluids ............................................................................... 10 2.2.3.3 YF500 and YF600 Fluids ............................................................................... 10 3 Crosslinked Oil-Base Fluids ..................................................................................................... 11 3.1 YF"GO"III and YF"GO"IV Fluids......................................................................................... 12 4 Multiphase Fluids ..................................................................................................................... 12 4.1 Foams ................................................................................................................................ 12 4.2 Energized Fluids ................................................................................................................ 12 4.2.1 The Gas Phase......................................................................................................... 13 4.3 Emulsions .......................................................................................................................... 14 5 Acidic Fluids ............................................................................................................................. 15 6 Fracturing Fluid Characterization............................................................................................. 16 6.1 Rheology............................................................................................................................ 16 6.1.1 Shear and Temperature ........................................................................................... 16 6.1.2 Shear Rate ............................................................................................................... 16 6.1.3 Shear Stress ............................................................................................................. 16 6.1.4 Apparent Viscosity .................................................................................................... 16 6.1.5 Newtonian Fluids ...................................................................................................... 17 6.1.6 Non-Newtonian Fluids .............................................................................................. 17 6.2 Slurry Rheology ................................................................................................................. 19 6.3 Proppant Transport ............................................................................................................ 21 6.4 Fluid-Loss .......................................................................................................................... 22 6.5 Conductivity Damage from Fracturing Fluids ..................................................................... 23 6.5.1 The Effect of Water-Base Fracturing Fluids on Retained Permeability .................... 24 7 Fluid 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Section 1200 Figures Fig. 1. The structure of guar. ........................................................................................................5 Fig. 2. The structure of HPG.........................................................................................................6 Fig. 3. The structure of HEC.........................................................................................................7 Fig. 4. The structure of Xanthan. ..................................................................................................7 Fig. 5. Borate crosslinking mechanism.........................................................................................9 Fig. 6. The structure of aluminum phosphate ester chain. .........................................................11 Fig. 7. Power-law exponent of a 40 lbm/1000 gal crosslinked water-base fluid. ........................17 Fig. 8. Consistency coefficient of a 40 lbm/1000 gal crosslinked water-base fluid. ....................18 Fig. 9. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 40 sec-1..........18 Fig. 10. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 170 sec-1.....19 Fig. 11. The effects of proppant on slurry viscosity of a Newtonian fluid....................................20 Fig. 12. The effects of proppant concentration on friction pressure of a water-base fluid. ........21 Fig. 13. Borehole fluid invasion zones........................................................................................23 Fig. 14. Effects of proppant concentration and porosity on postclosure polymer concentration.25 Fig. 15. Effect of polymer concentration on retained proppant-pack permeability......................26 Section 1200 Tables Table 1. Comparison Of Nitrogen And Carbon Dioxide..............................................................13 Section 1300 Appendix C - Additives 1 Introductory Summary ................................................................................................................2 2 Fracturing Fluid Components .....................................................................................................2 2.1 Activators..............................................................................................................................3 2.2 Buffers ..................................................................................................................................3 2.3 Crosslinkers..........................................................................................................................3 2.4 Emulsifiers ............................................................................................................................3 2.5 Foaming Agents ...................................................................................................................4 2.6 Polymers...............................................................................................................................4 2.7 Potassium Chloride ..............................................................................................................4 3 Fracturing Fluid Additives ...........................................................................................................4 3.1 Bactericides ..........................................................................................................................4 3.2 Breakers ...............................................................................................................................5 3.2.1 Breakers for Water-Base Fluids ..................................................................................6 3.2.1.1 Enzyme Breakers .............................................................................................6 3.2.1.2 Oxidative Breakers ...........................................................................................6 3.3 Clay Stabilizers.....................................................................................................................9 3.3.1 Clay Types ..................................................................................................................9 3.3.2 Clay Control Methods................................................................................................12 3.3.2.1 Ionic Neutralization.........................................................................................12 3.3.2.2 Organic Barrier ...............................................................................................13 3.3.2.3 Particle Fusion................................................................................................13 3.4 Fluid-Loss Additives ...........................................................................................................13 3.5 Friction Reducers ...............................................................................................................14 3.6 Temperature Stabilizers .....................................................................................................15 3.7 Surfactants .........................................................................................................................17 DOWELL CONFIDENTIAL



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3.7.1 Fluorocarbon Surfactants ......................................................................................... 22 3.7.2 Surfactant Selection.................................................................................................. 22 3.8 Nonemulsifying Agents ...................................................................................................... 23 3.8.1 Nonemulsifying Agent Selection ............................................................................... 23 4 Additive Selection..................................................................................................................... 25 Section 1300 Figures Fig. 1. Apparent viscosity of 40 lbm/1000 gal crosslinked fluids with methanol and sodium thiosulfate stabilizers....................................................................................................... 16 Fig. 2. Apparent viscosity of a 50 lbm/1000 gal crosslinked fluid containing sodium thiosulfate and a 60 lbm/1000 gal crosslinked fluid containing methanol......................................... 16 Fig. 3. Surfactant orientation...................................................................................................... 18 Fig. 4. The wettability of oil/water/rock. ...................................................................................... 20 Section 1300 Tables Table 1. Properties Of Common Dowell Surfactants ................................................................. 21 Table 2. The Effects of Wettability Change................................................................................ 21 Table 3. Summary of Surfactant Action on Mineral Surfaces .................................................... 22 Table 4. Properties Of Common Dowell Nonemulsifying Agents............................................... 24 Table 5. Additive Recommendation Guide................................................................................. 25 Table 6. Additive Selection Guide .............................................................................................. 26 Section 1400 Appendix D - Proppants 1 Introductory Summary................................................................................................................ 2 2 Physical Properties of Proppants ............................................................................................... 3 2.1 Proppant Strength................................................................................................................ 3 2.2 Grain Size and Grain-Size Distribution ................................................................................ 4 2.3 Quantities of Fines and Impurities ....................................................................................... 5 2.4 Roundness and Sphericity ................................................................................................... 6 2.5 Proppant Density ................................................................................................................. 6 3 Classes of Proppants ................................................................................................................. 6 3.1 Sand..................................................................................................................................... 6 3.2 Resin-Coated Proppants...................................................................................................... 6 3.2.1 Precured Resin-Coated Proppants............................................................................. 7 3.2.2 Curable Resin-Coated Proppants............................................................................... 7 3.2.3 Limitations Associated With Resin-Coated Proppants................................................ 7 3.2.3.1 Oxidative Breakers........................................................................................... 8 3.2.3.2 Borate-Crosslinked Fluids................................................................................ 9 3.2.3.3 Organometallic-Crosslinked Fluids .................................................................. 9 3.3 Intermediate-Strength Proppants......................................................................................... 9 3.4 High-Strength Proppants ..................................................................................................... 9 4 Conductivity ............................................................................................................................. 10 4.1 Closure Stress ................................................................................................................... 10 4.2 Embedment........................................................................................................................ 10 4.3 Fracture Width ................................................................................................................... 11 4.4 Proppant-Pack Porosity ..................................................................................................... 12 DOWELL CONFIDENTIAL



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4.5 Factors Operative in the Presence of Polymeric Fracturing Fluids ....................................13 5 Proppant Testing ......................................................................................................................13 6 Measurement of Proppant Addition to Fracturing Fluids ..........................................................14 7 Proppant Selection ...................................................................................................................16 8 Proppant Flowback...................................................................................................................16 Section 1400 Figures Fig. 1. Strength comparisons of various types of proppants. .......................................................4 Fig. 2. The effect of feldspar contamination on conductivity.........................................................5 Fig. 3. The relationship of proppant concentration and fracture width (no embedment). ..........12 Section 1400 Tables Table 1. Proppant-Pack Porosity Of Sand And Intermediate-Strength Proppant .......................12 Table 2. Density Table For Proppant Added To Fracturing Fluid ...............................................14 Section 1500 Appendix E - Fluid Loss 1 Introductory Summary ................................................................................................................2 2 Filtrate-Dependent Leakoff .........................................................................................................3 2.1 Wall-Building Coefficient.......................................................................................................5 2.2 Viscosity Control Coefficient.................................................................................................7 2.3 Compressibility Coefficient ...................................................................................................7 2.4 Fracturing Fluid Coefficient...................................................................................................8 2.5 Total Leakoff Volume............................................................................................................8 2.6 Fluid-Loss Mechanisms and Permeability ............................................................................8 3 Pressure-Dependent Leakoff......................................................................................................9 3.1 Geologic Discontinuities .......................................................................................................9 3.2 Opening Natural Fissures.....................................................................................................9 3.3 Fluid-Loss Control in Fissures ............................................................................................10 4 Types of Fluid-Loss Additives...................................................................................................11 4.1 Inert Particulates.................................................................................................................11 4.2 Soluble Particulates............................................................................................................11 4.3 Oil-in-Water Emulsions.......................................................................................................12 5 Formation Considerations ........................................................................................................12 5.1 Fluid Loss to the Rock Matrix .............................................................................................12 5.1.1 Pore-Size Determination ...........................................................................................13 5.1.1.1 Experimentally................................................................................................13 5.1.1.2 Calculation......................................................................................................13 5.2 Fluid Loss to Fissures.........................................................................................................13 6 In-Situ Measurement of Fluid-Loss Coefficients.......................................................................16 7 Guide to Dowell Fluid-Loss Additives .......................................................................................17 7.1 Fluid-Loss Additive Sizing ..................................................................................................18 Section 1500 Figures Fig. 1. Zones of invasion. .............................................................................................................3 Fig. 2. The relationship of the fluid-loss coefficient to fluid volume and fracture length. .............4 Fig. 3. Typical fluid-loss data for a wall-building fluid. ..................................................................6 Fig. 4. Log-log plot of fracture pressure indicating possible fluid loss to fissures......................10 DOWELL CONFIDENTIAL



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Opening of fissures. ........................................................................................................ 10 Idealized G Plot (from the DataFRAC software). ............................................................ 16 Bridging particle size versus pore-throat diameter.......................................................... 18 Bridging particle size versus approximate permeability. ................................................. 19



Section 1500 Tables Table 1. Influence Of Natural Fissures In Low-Permeability Rock............................................. 15 Table 2. Guide To Dowell Fluid-Loss Additives ......................................................................... 17 Section 1600 Appendix F - Equipment 1 Introductory Summary................................................................................................................ 2 2 Mixing and Blending Equipment................................................................................................. 4 2.1 PCM Precision Continuous Mixer ........................................................................................ 4 2.2 POD Blender ........................................................................................................................ 5 2.2.1 POD II Blender............................................................................................................ 7 3 Pumping Equipment................................................................................................................... 9 3.1 Pump Application Guidelines ............................................................................................... 9 3.1.1 Fracturing Fluid Viscosity............................................................................................ 9 3.1.2 Slurried Fluids Containing Proppant ........................................................................... 9 3.1.3 Proppant Concentration and Low Pump Speeds...................................................... 10 3.1.4 High Vapor Pressure Fracturing Fluids..................................................................... 10 3.1.5 Volumetric Efficiency ................................................................................................ 11 3.2 Nitrogen ............................................................................................................................. 11 3.3 Carbon Dioxide .................................................................................................................. 12 3.4 Pressure Multipliers ........................................................................................................... 12 4 Treating Equipment.................................................................................................................. 12 5 Sensors.................................................................................................................................... 13 6 Computing and Monitoring Equipment..................................................................................... 13 6.1 PACR Pumping, Acidizing, Cementing Recorder............................................................... 13 6.2 PPR Pumping Parameter Recorder ................................................................................... 13 6.3 FCS Computer System ...................................................................................................... 13 6.4 PAC Portable Acquisition Computer .................................................................................. 13 6.5 JMU Job Management Unit ............................................................................................... 14 7 Tools ........................................................................................................................................ 15 8 Support Equipment .................................................................................................................. 15 Section 1600 Figures Fig. 1. Equipment positioning for a fracturing treatment (typical)................................................. 3 Fig. 2. The RampFRAC Service................................................................................................... 5 Fig. 3. The stairstep method of proppant addition. ...................................................................... 6



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RESERVOIR EVALUATION 1 Introductory Summary............................................................................................................. 4 2 Well Performance..................................................................................................................... 5 2.1 Inflow Performance .............................................................................................................. 6 2.2 Tubing Intake ....................................................................................................................... 8 3 Well Test Interpretation ......................................................................................................... 10 3.1 Critical Variables ................................................................................................................ 11 3.2 Flow Regimes .................................................................................................................... 13 3.3 Boundary Effects................................................................................................................ 14 3.4 Diagnostic Plots ................................................................................................................. 15 3.5 Type Curves....................................................................................................................... 18 3.6 Computational System ....................................................................................................... 21 3.7 Steps for Analysis .............................................................................................................. 27 3.8 Example Analysis............................................................................................................... 30 4 Economic Analysis ................................................................................................................ 38 4.1 FracNPV Software ............................................................................................................. 40 5 Application ............................................................................................................................. 48 6 Eqquation Summary .............................................................................................................. 55 6.1 Oil IPR Equations............................................................................................................... 55 6.1.1 Darcy's Law ............................................................................................................... 55 6.1.2 Vogel Test Data ( Pr ≤ pb ) ......................................................................................... 55 6.1.3 Combination Vogel = Darcy Test Data ( Pr



≥



pb ) ....................................................... 55



6.1.4 Jones IPR .................................................................................................................. 57 6.2 Gas IPR Equations............................................................................................................. 58 6.2.1 Darcy's Law (Gas) ..................................................................................................... 58 6.2.2 Jones' Gas IPR (General Form) ................................................................................ 58 DOWELL CONFIDENTIAL



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6.3 Backpressure Equation ......................................................................................................59 6.4 Transient Period Equations ................................................................................................60 6.4.1 Time to Pseudosteady State......................................................................................60 6.4.2 Oil IPR (Transient) .....................................................................................................60 6.4.3 Gas IPR (Transient) ...................................................................................................61 6.5 Completion Pressure Drop Equations ................................................................................61 6.5.1 Gravel-Packed Wells .................................................................................................61 6.5.2 Open Perforation Pressure Drop ...............................................................................63 FIGURES Fig. 1. Pressure losses in complete systems (after Mach, Proano and Brown). ..........................5 Fig. 2. Location of various nodes (Mach et al., 1981)...................................................................6 Fig. 3. Typical IPR curve. .............................................................................................................7 Fig. 4. Vogel's composite IPR.......................................................................................................8 Fig. 5. Vertical multiphase flow: How to find the flowing bottomhole pressure. ...........................9 Fig. 6. Tubing intake curve. ..........................................................................................................9 Fig. 7. Deliverability of the producing system. ............................................................................10 Fig. 8. Well log............................................................................................................................12 Fig. 9. Well log............................................................................................................................12 Fig. 10. Radial flow. ....................................................................................................................13 Fig. 11. Linear flow in the formation. ..........................................................................................14 Fig. 12. Bilinear flow. ..................................................................................................................14 Fig. 13. Conditions associated with the boundries. ....................................................................15 Fig. 14. Pressure change and elapsed time to use in a drawdown. ...........................................16 Fig. 15. Log-Log plot. .................................................................................................................17 Fig. 16. Pressure change and elapsed time. ..............................................................................17 Fig. 17. Complete log-log behavior.............................................................................................17 Fig. 18. This is a reproduction from a type curve described in World Oil, (Oct. 1983). ..............19 Fig. 19. Series of pressure, pressure derivative, and specialized plots for common reservoir features..........................................................................................................20 Fig. 20. Diagnostic log-log plot. ..................................................................................................21 Fig. 21. Two Horner plots. ..........................................................................................................22 Fig. 22. Model-Verified Interpretation. ........................................................................................23 Fig. 23. Conceptual model catalog. ............................................................................................24 Fig. 24. NODAL plot. ..................................................................................................................25 Fig. 25. Sequence simulation. ....................................................................................................25 Fig. 26. Simulated validation. .....................................................................................................26 Fig. 27. PVT plot.........................................................................................................................26 Fig. 28. Matching a diagnostic log-log plot to a type curve.........................................................29 Fig. 29. Matching a diagnostic log-log plot to a type curve.........................................................29 Fig. 30. Log-Log Plot ..................................................................................................................30 Fig. 31. Generated type curve with the log-log diagnostic match...............................................32 DOWELL CONFIDENTIAL



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Fig. 32. Semilog presentation using a superposition type curve and the data points from the buildup. .......................................................................................................... 33 Fig. 33. Cartesian plot of the simulated pressure and the actual measured data...................... 33 Fig. 34. Decline curve and sensitivity plot. ................................................................................. 34 Fig. 35. Decline curve and sensitivity plot. ................................................................................. 34 Fig. 36. Sensitivity plot. .............................................................................................................. 35 Fig. 37. Sensitivity plot. .............................................................................................................. 35 Fig. 38. Sensitivity plot. .............................................................................................................. 36 Fig. 39. Sensitivity plot. .............................................................................................................. 36 Fig. 40. Sensitivity plot. .............................................................................................................. 37 Fig. 41. Plot of the transient IPR curves with the tubing intake and wellhead pressure of 875 psi....................................................................................................... 37 Fig. 42. Transient IPR plot for the same tubing, but using different wellhead pressures to generate the plot shown in Fig. 32. .............................................................................. 38 Fig. 43. Conceptual NPV calculation. Case A: revenue is larger than the cost, resulting in a positive NPV; Case B: revenue is less than the cost, resulting in a negative NPV. ..... 40 Fig. 44. Components of the NPV calculation. ............................................................................ 41 Fig. 45. Fracture in a bounded reservoir.................................................................................... 41 Fig. 46. Constant-rate type curve for finite-conductivity fracture  closed square system (xe/ye = 1). ...................................................................................................................42 Fig. 47. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 2). ...................................................................................................................42 Fig. 48. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 4). ...................................................................................................................43 Fig. 49. Transient IPR for a fracture well in a closed square reservoir. ..................................... 44 Fig. 50. Tubing intake curve....................................................................................................... 45 Fig. 51. FracNPV analysis for one, two and three years versus fracture length. ....................... 46 Fig. 52. Cumulative production versus fracture length............................................................... 46 Fig. 53. Production decline versus time. .................................................................................... 47 Fig. 54. Cumulative production versus time. .............................................................................. 47 Fig. 55. Well performance tracking form. ................................................................................... 51 Fig. 56. Well performance tracking form. ................................................................................... 53 TABLES Table 1. Results of Buildup Test ................................................................................................ 31 Table 2. Maximum Fracture Lengths for Drainage Shapes ....................................................... 43



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1 Introductory Summary Evaluation is a critical part of any process where understanding and improvement are goals. Understanding and improving the fracturing treatments demand that the best information be available for design, and that the results obtained from the execution of the design be analyzed. The appropriate fracturing treatment for a given well has been hard to design because of the numerous variables involved. The evaluation of fracturing treatments has been difficult because many of these same design variables are also used for production simulation. The use of inaccurate reservoir variables to design treatments therefore leads to poor production estimates. Many times a production estimate is not even made, and evaluation then ceases to be a part of the technology required to supply a value to the client. A successful fracturing treatment has too long been defined as “one that was pumped without problems.” A successful treatment needs to be defined as “one that provides the production predicted by the design process.” A fracture stimulation treatment should optimize production. Most of the time the treatment does not optimize production because realistic values for the critical variables used in the design process have not been properly identified. Critical variables are those variables that have the greatest impact on the production obtained from a fracturing treatment. Permeability, for example, is a critical variable. An accurate value for these variables (rather than general estimates) is very important for a realistic design and for accuracy in predicting the production response. Optimization is possible with proper identification and use of the accurate critical variables. The critical variables used to optimize stimulation treatments can be placed into three categories. Each category contains variables needed to determine specific design criteria. These three categories are (1) reservoir and producing system variables for determining the production response from the well, (2) stimulation design variables that determine achievable fracture geometry, and (3) economic variables that determine the optimum treatment. Reservoir evaluation deals primarily with the reservoir and producing system variables and with the economic variables. Design variables are covered in more detail in other sections of this manual. Reservoir and producing system variables are those variables obtained from well performance testing/analysis and from analyzing surface and wellbore plumbing configurations. Economics optimization deals with the production, net discounted production revenue and cost of the fracturing treatment. The teaching of the total technology involved in pressure transient and well performance analysis is beyond the scope of this section. The user should study the applicable references and attend training sessions on well performance testing whenever possible. Therefore, certain assumptions must be made and the section will deal with how to apply well performance data to fracture design and evaluation.



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2 Well Performance Well performance can be defined simply as the ability of a well to produce reservoir fluids to the surface by either natural flow or by artificial lift. The physical description of a typical well is shown in Fig. 1. The figure also illustrates the pressure losses that can occur from the reservoir to the separator. A node is any point in the production system between the drainage boundary and the separator where the pressure can be calculated as a function of the flow rates. Fig. 2 shows the location of various nodes in a producing system. It is important to understand the components of the production system, because different pressure-loss relationships are used in an analysis method for designing and optimizing the total system (NODAL* analysis).



Fig. 1. Pressure losses in complete systems (after Mach, Proano and Brown).



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Fig. 2. Location of various nodes (Mach et al., 1981). 2.1 Inflow Performance The Inflow Performance Relationship (IPR) is defined as the functional relationship between the production rate and the bottomhole flowing pressure. The IPR is defined in the pressure range between the average reservoir pressure and atmospheric pressure. The flow rate corresponding to the atmospheric pressure at bottomhole is defined as the absolute open flow potential (AOFP). A typical IPR for a single-phase liquid is shown in Fig. 3. Darcy's law for radial flow is used to obtain the flow rates necessary to construct this IPR. Using re = 1466 ft, rw = 0.583 ft, st = 0 and no turbulence, Darcy's law simplifies to qo =



kh µ o Bo



( pr − pwf ) (k in Darcy)



(1)



This simple equation is often used for the estimation of flow rates from oil wells.



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Fig. 3. Typical IPR curve. It was stated that the IPR shown in Fig. 3 is a straight-line relationship based on Darcy's law, and the AOFP is the maximum flow rate with the atmospheric pressure at the bottomhole. The Productivity Index (PI) is the absolute value of the slope of the IPR straight line. Therefore, a simple equation for PI can be written as follows. PI =



(



q pr − pwf



)



(2)



The two equations are shown to illustrate the basic simplicity in constructing and using the IPR, as well as to point out a reminder or caution when dealing with IPR curves. The PI concept is not used for gas wells because the rate in Darcy's equation for gas is a function of pressure squared. Consequently, the IPR becomes a curve rather than a straight line, and the slope therefore changes with the rate in this case. The PI concept cannot be used in two-phase systems (gas/liquid), because Darcy's equation can only be used to construct the portion of the line where the pressure is above the bubblepoint (pb) for a single-phase liquid system. The portion of the curve below the bubblepoint pressure must be corrected (Vogel's equation) for gas. Fig. 4 shows an example of a composite IPR and how the maximum production would be overestimated if Vogel's IPR was not applied.



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Fig. 4. Vogel's composite IPR. Vogel's IPR does not consider a skin factor, and therefore is only applicable for undamaged wells. Standing's extension of Vogel's IPR uses the concept of a flow efficiency factor (FE) to extend the effect of skin on Vogel's equation. The reader should examine the method Standing used, and also understand the concept of skin factors and the impact skin has on the producing system. 2.2 Tubing Intake The previous topic of inflow performance developed the concept of using Darcy's equation, and modifications, to construct IPR plots. Obviously, the characteristics of an IPR curve are sensitive to the variables used in the equations, and each change in any variable will produce a new IPR curve. The nodes examined so far deal with the actual reservoir variables. This new topic deals with the effect that the tubular configuration has on the production. Gradient curves are used to generate a plot of rate versus bottomhole flowing pressure. Gradient curves are available for a wide range of flowline or tubing size and a set of fixed flow and fluid parameters. Fig. 5 is an example gradient curve for 2-7/8-in. tubing and 1000 BPD of liquid production at 50% oil. A particular set of conditions is chosen (wellhead pressure, tubing diameters, and fluid type). The gradient curve is then used to obtain different rates versus bottomhole flowing pressure, and the tubing intake curve is constructed as shown in Fig. 6.



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Fig. 5. Vertical multiphase flow: How to find the flowing bottomhole pressure.



Fig. 6. Tubing intake curve.



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Additional comments concerning Fig. 6 are: •



Negative slope at low rate is indicative of unstable flow in the pipe.



•



Inflection point in the curve is the critical rate below which the gas will slip by the liquid and the well will load up. Any rate below the critical rate will kill the well.



•



Positive-slope portion of the curve shows the conditions where the velocity is high enough to move the fluids to the surface.



The tubing intake curve plotted with the IPR curve is shown in Fig. 7. The intersection of the two curves determines the deliverability of the producing system.



Fig. 7. Deliverability of the producing system. Additional information is available in the references, which cover in more detail the nodes that can be analyzed similar to the intake curve. Perforation size and density, for example, can have a major impact on the production.



3 Well Test Interpretation Reservoirs not only differ in lithology but also in behavior. Testing in many different reservoirs has shown that the possible number of behaviors from a well test is limited to three; therefore, only a few interpretation models are required for analysis. The three main types of behavior are (1) homogeneous, (2) dual porosity, and (3) dual permeability. 1. Homogeneous Behavior. There is only one porous medium producing into the well. This is an overall definition (mathematical) and does not actually mean that the reservoir is homogeneous, but that there is a characteristic shape of the reservoir pressure response to a change in rate.



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2. Dual-Porosity Behavior. Two homogeneous porous media are interacting. Each medium is of distinct porosity and permeability and can be uniformly distributed, or they can be segregated. However, only one medium produces fluid into the well and the other medium acts as a source. Dual-porosity behavior may be used to explain naturally fractured or fissured reservoirs •



single-layered reservoirs, but with high-permeability variation through the reservoir thickness



•



reservoirs that are multilayered with a high-permeability contrast between the layers.



3. Dual-Permeability Behavior. Two distinct porous media, each producing into the well. This behavior may be described as multilayered reservoir with lowpermeability contrast •



multiple zones separated by impermeable layers



•



partial completion.



These three types of behavior have certain characteristics that are recognizable on various diagnostic plots that will be discussed later. 3.1 Critical Variables There are three critical variables obtained from well test interpretation, (1) reservoir pressure, (2) skin, and (3) permeability. Permeability can be obtained from core analysis, but unless the analysis is performed under in-situ conditions the permeability could be off several orders of magnitude too high. Permeabilities obtained from pressure tests are considered the most reliable for true reservoir permeability because these tests are a direct measure of the in-situ reservoir response. Because the correct interpretation of the pressure test data is critical for accurate permeability and flow-rate predictions, it is important to note and keep in mind the following. •



All well-test-interpretation equations are solved in terms of kh/(µβ) (transmissibility). Therefore, an accurate calculation of k depends on accurate values for reservoir thickness, fluid viscosity, and formation volume factor.



•



All well test interpretations make the assumption that there is a major producing phase, either oil, oil and water (total liquid) or gas. Values for the viscosity and formation volume factor are based on the major phase of production. For a well producing oil and water, a weighted average viscosity and weighted average volume factor should be used to calculate k.



Remember that h is the net productive interval and not just the perforated height (hp). The net interval thickness is also different from the gross thickness (hg) normally used as height growth when designing or evaluating hydraulic fracturing. Fig. 8 and Fig. 9 are examples of well logs showing the possible combinations of net, perforated and gross height.



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Fig. 8. Well log.



Fig. 9. Well log.



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3.2 Flow Regimes Pressure transient analysis is used to analyze the pressure change with time under the constant producing rate or constant bottomhole pressure. Wells can be unstimulated, acidized or stimulated with hydraulic fractures that are either etched or propped. Stimulation alters part of the producing system and can dramatically increase the production. These different well conditions have different flow regimes that affect the pressure behavior at the well. The following flow regimes are important for the purpose of analysis. •



Radial Flow. Flowlines at all elevations in the porous zone around the wellbore are radial. Radial flow converges in producing wells and diverges in the case of injection wells. Fig. 10 illustrates this regime.



•



Linear Flow. Wells that have been hydraulically fractured can show both linear flow from the matrix to the fracture and linear flow along the fracture to the wellbore. The dominant flow for a well with a very high-conductivity fracture will be from the matrix to the fracture. Fig. 11 illustrates linear flow.



•



Bilinear Flow. The flow of fluid in a well with a finite-conductivity fracture depends not only on the linear flow from the matrix but also the linear flow along the fracture. The bilinear flow regime is shown in Fig. 12.



Fig. 10. Radial flow.



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Fig. 11. Linear flow in the formation.



Fig. 12. Bilinear flow. Fluid flow in porous media is expressed mathematically by the diffusivity equation. This equation is a partial differential equation and is solved with specific inner (wellbore) and outer boundary conditions. 3.3 Boundary Effects Transient tests in wells show that the pressure response is affected by boundary conditions as well as by the basic reservoir behavior such as homogeneous, dual porosity and dual permeability. Fig. 13 shows the conditions associated with the boundaries. Some additional comments are made to clarify outer boundaries.



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Fig. 13. Conditions associated with the boundaries. •



Constant pressure outer boundary assumes the reservoir has an active water drive or pressure maintenance program (fluid injection) that maintains constant reservoir pressure (steady state). This also means that fluid produced from the well will be replaced at the same rate by fluid flowing across the boundary.



•



A closed outer-boundary reservoir can never reach steady state because fluid is not replaced. This no-flow outer boundary can be set by impermeable barriers, faults, pinchout, or other producing wells across the boundary. The transient pressure response does reach the outer boundary at late times when the rate of pressure change with time is constant. This is called the pseudosteady state. The time needed to reach the pseudosteady state is dependent on the geometry (shape factor) of the reservoir.



3.4 Diagnostic Plots Pressure transient analysis is basically a pattern-recognition process and involves plotting the pressure change versus time. The diagnostic plot is the first plot which must be made in any analysis. This is a log-log plot (using all of the available data) of pressure function change versus time during the period to be analyzed. The loglog scale is used because it allows the characteristic shape of a response to be observed without distortion due to the range of data. The diagnostic log-log plot is used to •



select the basic interpretation model



•



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calculate the parameters from the comparison of the log-log curve and type curves.



A pressure function must be selected when generating a log-log plot. Use the direct pressure change for oil wells, and pressure squared for gas wells. Real gas pseudopressure, M(p), is preferred for gas wells when computer software is used. See the references for a more detailed discussion on pressure functions. Analysis can be made using drawdown data as well as buildup data. Fig. 14 shows the pressure change and elapsed time to use in a drawdown. The log-log plot will appear as shown in Fig 15. Fig. 16 shows the pressure change and elapsed time to use when a log-log plot is made to analyze buildup data. The pressure response of any period is affected by the prior periods, and therefore pressure transient analysis of a buildup must take into account the effects of the previous flow period. The transient effects of the flow period continue to affect the pressure in the reservoir after the well is shut in. This effect is not indicated on the pressure recorder. The complete log-log behavior is illustrated in Fig. 17, which shows a well with wellbore storage in a closed homogeneous reservoir. Specialized plots can be used to confirm the flow regime identified on the diagnostic log-log plot. Details of the specialized plots will not be covered, but examples will be shown later.



Where: pwf (∆t) = flowing pressure at ∆t, = initial pressure, pi = time when the well was opened, and to ∆p(∆t) = pi - pwf (∆t)



Fig. 14. Pressure change and elapsed time to use in a drawdown.



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Fig. 15. Log-log plot.



Fig. 16. Pressure change and elapsed time. Note: This is the pressure change and elapsed time to use when a log-log plot is made to analyze buildup data.



Fig. 17. Complete log-log behavior.



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3.5 Type Curves Type curves are graphical representations of the solution of the diffusivity equation for the constant rate drawdown under different boundary conditions. Type curves are available for many reservoir and well types. Some of these type-curve combinations are • homogeneous reservoir with or without wellbore storage and skin •



homogeneous reservoir with or without induced fractures in the wellbore



•



dual porosity or naturally fractured reservoirs



•



layered reservoir.



The three variables in the x, y, and z dimensions in the type curve are dimensionless pressure, dimensionless time and a variable representing either the near wellbore condition or the boundary shape. Depending on the wellbore condition, the z variable may be (1) wellbore storage, c, and skin, s, in the case of homogeneous reservoirs or (2) fracture conductivity, CfD, in the case of wells with an induced fracture. Fig. 18 is a type curve for a homogeneous reservoir with wellbore storage and skin. The advantage of this type curve is the ease of matching and clear definition of the flow regimes. The dimensionless variables for this type curve are shown on the upper portion of the curve. The presentation of these dimensionless variables in log-log coordinates makes it possible to match the pressure versus time data obtained from a well test. The use of a pressure derivative represents a major advancement in pressure transient analysis. The derivative is useful because not only the pressure curve but also the pressure derivative curve must match the analytical solution. Pressure trends can be confusing at middle and late times and subject to many interpretations, but the derivative values are much more definitive. Fig. 19 is a series of pressure, pressure derivative and specialized plots for common reservoir features.



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Fig. 18. This is a reproduction from a type curve described in World Oil, (Oct. 1983). The original graph is in three colors.



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Fig. 19. Series of pressure, pressure derivative, and specialized plots for common reservoir features.



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3.6 Computational System Mistakes based on incorrect well test analysis can be embarrassing and costly. It has become too time consuming to process well test data by hand, and the margin of error is too high. Therefore, a more economical and practical analysis system is necessary. The STAR* (Schlumberger Transient Analysis and Report) software incorporates the essentials of modern reservoir engineering. This comprehensive computational system is easily capable of handling the most complex transient analysis. The software is menu driven, and correct results can be obtained with a minimum of training. The system is capable of performing sensitivity analysis (NODAL analysis), validation and interpretation. The following is an example of the difficulty in making an interpretation, and how the derivative and a model to verify the interpretation are tremendous advantages for well test interpretation. A 30-hr buildup test was conducted on a Mid-Continent oil well. Fig. 20 is the diagnostic log-log plot indicating that the Horner analysis straight line might be difficult because of the changes indicated at Point A and Point B.



Fig. 20. Diagnostic log-log plot. Fig. 21 shows two Horner plots, one with the straight line through the points at A and the other through the points at B. The permeability and skin for each interpretation are shown. The question now becomes “which is the correct Horner straight line?” The answer is neither.



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Fig. 21. Two Horner plots. Fig. 22 is the Model-Verified Interpretation of the test data, and indicates the presence of a heterogeneous system. A two-porosity model with decreasing wellbore storage matches the entire buildup, and note the difference in permeabilities and skin. Anyone can draw a Horner straight line, but it must be the correct straight line. Fig. 19 is by no means all encompassing, but is there a similar type pattern to that shown in Fig. 22.



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Fig. 22. Model-verified interpretation. The STAR software can be used to actually suggest the proper type of test, and select the test objectives that are directly related to well productivity. The first step is to select a conceptual model most closely resembling the well, and match it with the petrophysical parameters of each productive zone derived from the log and geological data. Fig. 23 shows the conceptual model catalog of the program.



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Fig. 23. Conceptual model catalog. The NODAL analysis part of the software can be used to include a comparison of the completion variables and, at the same time, study the economics of the completion options. Fig. 24 shows an example NODAL plot of some selected completion options. The actual test sequence can now be simulated. This simulation is a twopart process best described as a series of flow-rate variations and flow periods necessary to achieve the desired results. The test sequence can be simulated within the software to allow the estimation of the ranges of values that will be encountered in the test. Validation of the design is accomplished by simulating the interpretation to verify that the test will determine the targeted objectives. Fig. 25 shows an example simulation of a test sequence and expected response. Fig. 26 is the second part, and is an example of the simulated validation showing the estimation of the times for essential test features such as the end of the wellbore storage, onset of DOWELL CONFIDENTIAL



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boundary conditions, etc. Fluid-phase behavior can now be considered at this time to ensure that the tests are not unnecessarily complicated by phase changes. Fig. 27 is an example of a simulated PVT plot. The software calculates all fluid properties, and the option is available to input actual PVT data. In many cases, the calculated values compare very close to the values from real PVT data on given well.



Fig. 24. NODAL plot.



Fig. 25. Sequence simulation.



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Fig. 26. Simulated validation.



Fig. 27. PVT plot.



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3.7 Steps for Analysis Analysis requires the well test data, well and formation data, and fluid data. Well test data required are •



Pressure (p)



•



Rates (q)



•



Time (t).



Well and formation data required are •



Depth (at midpoint of perforations)



•



Tubing Size



•



Wellbore Radius (bit size) (rw)



•



Formation Thickness (net producing interval)



•



Perforated Thickness



•



Perforation Size and Density



•



Formation Temperature (T)



•



Porosity (fraction).



Fluid data required are •



Liquid (oil)gravity (either specific or API) − gas/oil ratio (GOR) − bubblepoint pressure (pb) − formation/volume factor (βo) − viscosity (µ) − compressibility (co) − solution gas/oil ratio (Rs).



•



Gas − specific gravity − formation/volume factor (βg) − critical pressure (pc) − critical temperature (Tc) − gas deviation factor (Z) − viscosity (µ) − compressibility (cg). DOWELL CONFIDENTIAL



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Assuming all of the data are available, six steps should be completed for a successful analysis. The STAR software performs these steps very quickly, and may or may not follow the exact sequence. 1. Draw the log-log diagnostic plot. Use the type curve that will be used and lay tracing paper over the type curve. Trace the main grids and mark the scales. Plot the pressure and time data on the tracing paper but do not draw a line through the points. 2. Identify the flow regimes. For example, the early time will exhibit the characteristic shapes (usually one dominates) such as wellbore storage (unit slope), finite-conductivity fractures (quarter slope) or high-conductivity fractures (half slope). Refer again to Fig. 13 to see the characteristics that can be associated with the middle and late time. 3. Specialized plots (Cartesian or semilog) may now be drawn using only those individual data points that indicated the special shape on the diagnostic log-log plot. Wellbore storage, for example, is a unit slope and should therefore be a straight line through the origin on a Cartesian plot. Finite-conductivity fractures are quarter slope and a Cartesian plot of the pressure versus the fourth root of the time will also be a straight line passing through the origin. The references show many examples of these plots. 4. Calculate the parameters from the specialized plots. Caution is recommended and a reminder that accurate parameters must be obtained for the analysis to be beneficial. It is again recommended that the beginner study the references and have access to the STAR software as well as someone that can explain the software. 5. Select the most appropriate type curve based on the previous analysis showing the most likely reservoir behavior and well type. Place the diagnostic log-log plot over the type curve and shift it to a position which gives a best fit. The axis of the two graphs must be parallel at all times. Select a match point. This match point can be anywhere, but choose a point that is easy to identify such as the intersect of the major axis. Record the match point coordinates of the diagnostic plot (pressure and time) and the dimensionless values of the underlying type-curve grid (tD and pD). These values can now be used to calculate the desired parameters using the equations given in Fig. 18. An example of how to match a diagnostic log-log plot to a type curve is shown using Fig. 28 and Fig. 29. Make a copy of each of these and then use a light table or window to practice moving the plot to get the match shown, while keeping the axis parallel.



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Fig. 28. Matching a diagnostic log-log plot to a type curve.



Fig. 29. Matching a diagnostic log-log plot to a type curve. 6. Check for the consistency of the results. Numerical results from specialized analysis and from the log-log type-curve analysis should agree with less than 10% error. Be sure that the data points used to identify the flow regime on the specialized plots also match the same flow regime on the type curve. Verify that the straight line has been drawn through the correct points. Verify that the right match point was selected. If a consistent result cannot be obtained, then it is possible that the wrong model was selected.



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3.8 Example Analysis This example shows the steps as well as an example of an analysis made using the STAR software. This is a real well test from a gas well that had been fracture stimulated (with proppant) several years prior to the buildup. Real PVT data were not available so the calculated data were used. Additional well parameter data are •



total compressibility (1/psi)



= 2.098E-04



•



gas gravity



= 0.65



•



liquid/Gas Ratio (STB/MMscf)



= 1.90



•



viscosity (cp)



= 0.01946



•



porosity (%)



= 8.6



•



reservoir temperature (°F)



= 275



•



hole size (in.)



= 7.875



•



net pay (ft)



= 31



The buildup test was successful (see data in Table 1), and the data were first analyzed by a log-log diagnostic shown in Fig. 30. The log-log plot is laid over the type curve for a preliminary match that just serves as the starting point for the analytical solver in the software. The solver is a numerical simulator and obtains a unique match of the well test data.



Fig. 30. Log-log plot. DOWELL CONFIDENTIAL



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Table 1. Results of Buildup Test TEST PHASE: SHUTIN PERIOD # 1



FINAL FLOW PRESSURE - 1461 PSIA PRODUCING TIME - 48930 HR



TIME OF DAY HH:MM;SS



DATE



ELAPSED



DELTA



DELTA P



TIME, HR



BOT HOLE PRESSURE PSIA



PSI



LOG HORNER TIME



DD-MMM



TIME, HR



12:00:01 12:04:48 12:30:00 12:49:48 13:09:36 13:30:00 13:49:48 14:00:00 14:15:00 14:30:00 14:45:00 15:00:00 15:15:00 16:30:00 17:30:00 18:30:00 20:00:00 21:00:00 22:00:00 23:00:00 0:00:00 1:00:00 2:00:00 4:00:00 6:00:00 8:00:00 10:00:00 12:00:00 16:00:00 20:00:00 0:00:00 4:00:00 8:00:00 12:00:00 20:00:00 4:00:00 12:00:00



9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 9 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 10 - MAR 11 - MAR 11 - MAR 11 - MAR 11 - MAR 11 - MAR 12 - MAR 12 - MAR



0.000 0.080 0.500 0.830 1.160 1.500 1.830 2.000 2.250 2.500 2.750 3.000 3.250 4.500 5.500 6.500 8.000 9.000 10.000 11.000 12.000 13.000 14.000 16.000 18.000 20.000 22.000 24.000 28.000 32.000 36.000 40.000 44.000 48.000 56.000 64.000 72.000



0.000 0.080 0.500 0.830 1.160 1.500 1.830 2.000 2.250 2.500 2.750 3.000 3.250 4.500 5.500 6.500 8.000 9.000 10.000 11.000 12.000 13.000 14.000 16.000 18.000 20.000 22.000 24.000 28.000 32.000 36.000 40.000 44.000 48.000 56.000 64.000 72.000



1461 1729 1752 1801 1823 1837 1848 1854 1860 1867 1872 1878 1880 1903 1912 1923 1936 1946 1952 1960 1968 1972 1979 1988 2000 2009 2018 2027 2041 2053 2068 2078 2091 2104 2123 2144 2159



0 268 291 341 362 376 387 393 399 406 411 417 420 442 451 462 476 486 491 499 507 512 519 527 540 549 558 566 580 592 607 618 630 644 662 683 698



5.7874 4.9908 4.7706 4.6252 4.5135 4.4272 4.3886 4.3374 4.2917 4.2503 4.2125 4.1777 4.0364 3.9493 3.8767 3.7866 3.7354 3.6897 3.6483 3.6105 3.5758 3.5436 3.4856 3.4345 3.3887 3.3474 3.3096 3.2427 3.1847 3.1336 3.0879 3.0465 3.0088 2.9419 2.8840 2.8329



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Fig. 31 is the generated type curve with the log-log diagnostic match. The best-fit type curve was a homogeneous, finite-conductivity vertical fracture with variable wellbore storage. Note that all of the critical parameters have been calculated at this point in the process. Two model-verification plots were then produced. Fig. 32 is a semilog presentation using a superposition type curve and the data points from the buildup. Fig. 33 shows the other model verification using a Cartesian plot of the simulated pressure and the actual measured data. Production decline curves were then generated to predict the future production of the zone (1) under current conditions, and (2) if the liquid/gas ratio were changed. NODAL analysis was used to generate these two decline curves (Fig. 34 and Fig. 35) as well as the sensitivity plots that follow. Fig. 36 is a sensitivity plot showing the change in the production with the change in the wellhead pressure. The analysis then evaluated what the new production would be if the well were refractured. A fracture conductivity of 1400 md-ft was input to generate the sensitivity analysis of production, time and fracture length. Fig. 37 through Fig. 40 show these sensitivity plots.



Fig. 31. Generated type curve with the log-log diagnostic match.



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Fig. 32. Semilog presentation using a superposition type curve and the data points from the buildup.



Fig. 33. Cartesian plot of the simulated pressure and the actual measured data.



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Fig. 34. Decline curve and sensitivity plot.



Fig. 35. Decline curve and sensitivity plot.



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Fig. 36. Sensitivity plot.



Fig. 37. Sensitivity plot.



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Fig. 38. Sensitivity plot.



Fig. 39. Sensitivity plot.



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Fig. 40. Sensitivity plot. Fig. 41 is the plot of the transient IPR curves with the tubing intake and wellhead pressure of 875 psi. Fig. 42 is the transient IPR plot for the same tubing, but using different wellhead pressures to generate the plot shown in Fig. 32.



Fig. 41. Plot of the transient IPR curves with the tubing intake and wellhead pressure of 875 psi.



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Fig. 42. Transient IPR plot for the same tubing, but using different wellhead pressures to generate the plot shown in Fig. 32.



4 Economic Analysis Up to now this study has dealt primarily with evaluating the reservoir and plumbing system to obtain values for the critical variables, and to allow an accurate estimation of production at the surface where the production is actually measured and sold. The example analysis in the STAR software showed that hydraulic fracturing should also be evaluated because of the impact fracturing has on the reservoir. Not only does the reservoir deliverability and producing system need consideration, but also the fracture mechanics, fracturing fluid characteristics, proppant and transport of the proppant, operational constraints and economics. All of these considerations must be integrated to produce the most cost-effective design, and to maximize the benefits of a fracturing treatment. Maximizing these benefits requires a balance between the fracture characteristics and reservoir properties to optimize the reservoir deliverability. The final fracture design must be achievable from the execution approach, and the cost of the treatment versus the value obtained must be considered for true optimization. Value is critical because money not only has a current purchasing value, but it also has a time value. Even if risk and inflation are not considered, a dollar today is worth more than the same dollar a year from now because the dollar can be invested during the year. When the dollar is invested, it earns interest. Expressing the concept very simply, the present value (PV) of an amount is the time zero value of a future cash flow (FV) discounted N years at a % interest rate (i) per period. A simple equation expressing this and the Net Present Value (NPV) is as follows.



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PV =



FV



(1 + i )



Section 100 May 1998 Page 39 of 65 (3)



n N



Discounted Well Revenue = Σ



n= 1



Total Annual Net Revenue During Yr n



(4)



(1 + i )n Total Net Revenue (TNR) $/BBL or MCF X (frac - nonfrac) production. The fracture NPV is then expressed as Fracture NPV = Discounted Well Revenue - Treatment Cost. Many companies have software to evaluate economics through the NPV as it relates to fracturing. However, it is doubtful if very many have the entire analysis package. FracNPV analysis uses the fracture NPV to select the optimum propped fracture treatment for a specific well and reservoir conditions. The software couples the reservoir response, well hydraulics, fluid rheology, fluid volume and proppant concentration, pumping parameters, rock properties, and closure stress value. A range of fracture lengths is used and the economics are applied using the NPV concept. The rate of return can be misleading when dealing with incremental revenues; therefore, the optimum fracture size is defined as the one that provides the maximum NPV. Fig. 43 illustrates the NPV concept with two cases. Case A shows that the incremental revenue far exceeds the cost over the fracture lengths shown. Subtracting the cost from the revenue results in the characteristic bellshaped curve of the NPV. Some wells may not be good candidates for fracturing, and Case B shows an example where the incremental revenue does not justify the cost because the NPV curve is negative.



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Fig. 43. Conceptual NPV calculation. Case A: revenue is larger than the cost, resulting in a positive NPV; Case B: revenue is less than the cost, resulting in a negative NPV. 4.1 FracNPV Software Many of the calculations made by the software are invisible to the user. Therefore, a basic understanding of how the system processes the reservoir data is necessary. Fig. 44 illustrates the components of the system. Note that the geometry models are incorporated to simulate all aspects of the fracture mechanics. NODAL analysis and the application of the NPV concept for economics complete the system package.



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Fig. 44. Components of the NPV calculation. The reservoir is assumed to be a horizontal, isotropic, homogeneous, porous medium bounded by the top, bottom, and outer impermeable strata. Also, the reservoir has constant initial pressure, permeability, porosity and thickness. The geometry of the drainage region can be a square or rectangle. A finite-conductivity fracture contacts the well and penetrates the entire vertical extent of the formation. This fracture is assumed to have a constant permeability, porosity, and width. The flow entering the wellbore comes only through the fracture and obeys Darcy's law in the entire system. The properties of the reservoir and fracture are independent of pressure. Fig. 45 is a plan view of the physical system modeled, and shows a fracture in a bounded reservoir.



Fig. 45. Fracture in a bounded reservoir. DOWELL CONFIDENTIAL



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A method is now needed to predict the production. Remember from the previous discussion that IPR curves are used for this purpose. The software uses constantrate drawdown type curves for a well located at the center of a closed square reservoir. Fig. 46 through Fig. 48 show the type curves that exist numerically within the software.



Fig. 46. Constant-rate type curve for finite-conductivity fracture  closed square system (xe/ye = 1).



Fig. 47. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 2).



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Fig. 48. Constant-rate type curve for finite-conductivity fracture  closed rectangular system (xe/ye = 4). The software uses these type curves to calculate the IPR curves based on the critical variables one inputs to the various parameter screens. Remember also that the transient pressure behavior can last for a long period of time, especially in lowpermeability reservoirs. Notice on the type curves that since the reservoir is bounded, with no flow across the boundary, the curves go upward. The point at which each curve on the plot starts to bend upward is the end of the transient flow and the beginning of the pseudosteady-state flow. Also notice that the early time behavior is influenced primarily by the fracture conductivity, and that the late time pressure behavior is mostly dependent on the fracture penetration and reservoir geometry. Table 2 shows the fracture lengths for various drainage shapes noted on the type curves.



Table 2. Maximum Fracture Lengths for Drainage Shapes Drainage Area (acres)



Square



Shape 1x2



1x4



40



660



933



1320



80



933



1320



1866



160



1320



1866



2640



320



1866



2640



3733



640



2640



3733



5280



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The optimum fracture length is a function of the reservoir properties and not the drainage area assigned to the well. Therefore, if the software indicated an optimum length of 1000 ft, for example, and the client has used 40-acre spacing, Table 2 shows the best shape would be either 1 x 2 or preferably 1 x 4. This shows that to fully exploit the reservoir, the wells should be spaced in a rectangular pattern. The fracture azimuth must be known to plan this type of spacing. If these wells have already been drilled in a square pattern, the optimum fracture length is still not necessarily 660 ft. The azimuth of the fractures should be determined and then the drainage boundaries reconsidered. To optimize the production, each component must be analyzed separately and then as a combination to evaluate the entire system. Fig. 49 shows an example IPR curve that the software might generate internally for various fracture lengths and Fig. 50 shows a tubing intake curve for two different pressures.



Fig. 49. Transient IPR for a fracture well in a closed square reservoir.



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Fig. 50. Tubing intake curve. Using all of the input data, the analysis is made and one may choose to plot a family of curves similar to those shown in Fig. 51 through Fig. 54. The graphics screen shows the options available for immediate plots. Parametric studies can also provide valuable information for evaluating the effect one variable may have on another. Holding the NPV and fracture half-length as the axis, the effect of the various tubing sizes, formation permeabilities, injection rates, fracturing fluid viscosities, fracture heights, leakoff coefficient and many others can be compared and used for redesign if necessary.



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Fig. 51. FracNPV analysis for one, two, and three years versus fracture length.



Fig. 52. Cumulative production versus fracture length.



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Fig. 53. Production decline versus time.



Fig. 54. Cumulative production versus time.



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There are some cautions and design considerations that need to be mentioned when working with the software. These cautions and considerations are stated as follows. •



A single-phase simulator was used to generate the type curves used in the software, and Vogel's correlation is applied below the bubblepoint pressure. It is very important to use the correct pressures.



•



Multiple fracturing fluids may be input, but the software will not pick the best one for the treatment. The software uses the fluid that is most effective for the particular segment of length. This feature is useful when trying to obtain the highest pump rate possible, by varying the fluid viscosity, in cases where the net pressure is a limiting factor. The software cannot simulate viscosity degradation, and assumes the first fluid has degraded to the values of the second fluid, etc. It may be best to use only one fluid in a rerun, that fluid being the one shown for the length desired. The exception would be those designs where one is actually going to use a variable fluid viscosity system.



•



The best proppant is not picked if more than one is listed on the screen. Each proppant is considered a separate case and printed out as such. NOTE: the graphics produced are only for the first proppant listed.



•



The program does not contain the two-phase material balance calculations for the long-term prediction of the production.



•



The type curves used in the program are very good for low-permeability reservoirs (1 md or less), and depending on the actual value of the permeability may be accurate to five years. For permeabilities over 1 md, the transient time could be much less than the life of the well; therefore, the accuracy of the production rate decreases. This latter case, again depending on the actual permeability, could be accurate for possibly only one year.



The application of the FracNPV software exists whenever a propped fracture stimulation treatment is designed. Software is constantly upgraded, so the reader should periodically examine the applicable documentation. Also, many good examples of treatments run using the software are available in the references and the reader should study these as examples. The inclusion of examples such as these is too voluminous for the purpose of this section topic.



5 Application The primary goal of this manual section (Reservoir Evaluation) was to acquaint the reader with the technology involved in obtaining those variables that are so critical for designing the best fracturing treatment, and then being able to evaluate that treatment using the same technology. Many tools and methods were shown to make the job easier. Learn who and where to go for help in using some of the more complex systems. The method of reservoir evaluation, from obtaining the critical variables to evaluating the actual treatment, might be listed and summarized as follows. DOWELL CONFIDENTIAL



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1. Design and complete a valid well-performance test prior to any hydraulic fracturing. The design should consider both an appropriate flow time and shut-in time to obtain the needed data. Sometimes this well test may be a drill-stem test (DST). 2. Construct a log-log grid corresponding to the grid on the type curves. Plot the data (in the appropriate pressure and time functions) on the grid to construct the diagnostic plot. 3. Study the log-log plot for the pattern recognition of the wellbore storage, flow regimes, fractures, reservoir type, boundaries, etc. Use the specialized plot(s) if necessary to help identify some of the characteristics if unsure. 4. Select the basic type curve and place the log-log plot over it. Keep the axis of the two graphs parallel and obtain the best fit. Record the match points and corresponding dimensionless time and pressure. Calculate the desired variables using the type-curve equations. Check for consistency. 5. Design an optimized fracturing treatment using the FracNPV software. A very good estimation of the gross fracture height is needed, and the fracture-height log would be a good source. Parametric studies can be made to examine the influence of one set of variables on another set to help choose the correct fracturing fluids, proppants, etc. 6. Execute the treatment exactly as designed, monitoring and recording the critical parameters. Tag the fracturing fluid or use any method that will allow the fracture-height determination after the job. If treatment differs from the actual design, then rerun the actual treatment through the software to obtain a new production estimate. 7. Track the production results at least monthly. This is where most of an evaluation falls apart. Once the treatment has been pumped, the tendency is to forget about it and go on to the next one. The evaluation will never progress unless an effort is made to follow through. Not only is it important to know that the production response was very good, but also if the response was not what one predicted. Fig. 55 is a form that might be considered for use in tracking the well performance and for having a summary of the job parameters and critical variables. Fig. 56 is an example of the tracking form used on an actual well. 8. If production results are not as predicted by the design or the modified design after knowing the fracture height, then design a well performance test to evaluate the reservoir containing a fracture. It is very helpful to have the original permeability from an unfractured case to use to help determine the other parameters in a fractured case. This is the reason a well test was recommended prior to fracturing. Knowing the reservoir is now fractured, the mechanics and duration of the actual test can be designed.



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9. Repeat the process as in Step 1 through Step 4, being especially watchful for the characteristic finite conductivity of a fracture. Calculate the fracture dimensions and determine if they are realistic. If not realistic, review the test analysis and fracturing treatment for error. If realistic, run the parameters back through the design software to see what variables need to be changed to match the production as well as the parameters obtained from the well test. Be aware that if the original fracturing treatment was not designed properly (insufficient proppant at distance in the fracture), then the fracture may show up as being short on a well test. The test always indicates the effective fracture length. The engineer designing the treatment needs to be sure the fracture length will be effective. Reservoir evaluation is a must for an effective hydraulic fracture design and for determining if the actual fracturing treatment was successful. The treatment was successful if it provided the production predicted by the process the user designed.



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Fig. 55. Well performance tracking form.



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Fig. 55 (back).



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Fig. 56. Well performance tracking form. DOWELL CONFIDENTIAL



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Fig. 56 (back). DOWELL CONFIDENTIAL



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6 Equation Summary 6.1 Oil IPR Equations 6.1.1 Darcy's Law qo =



PI =



7.08 × 10 −3 kh( pr − pwfs )  r  3  µ o Bo ln e  − + s    rw  4  q q = = pr − pwfs ∆p



7.08 × 10 − 3 kh  r  3  µ o Bo ln e  − + s    rw  4 



AOF = ( PI )( pr − 0) Where: q = oil flow rate (B/D) AOF = absolute open flow potential (B/D) k = permeability (md) h = net vertical formation thickness (ft) pr = average formation pressure (shut-in BHP) (psi) pwfs = average flowing bottomhole pressure at the sandface (psi)



µo = average viscosity (cp) Bo = formation volume factor (res bbl/STB) re = drainage radius (ft) rw = wellbore radius (ft) S = skin factor (dimensionless) PI = Productivity Index (B/D/psi) 6.1.2 Vogel Test Data ( Pr ≤ pb ) qo qo max



pwfs  pwfs  = 1 − 0.2 − 0.8  pr  pr 



2



6.1.3 Combination Vogel = Darcy Test Data ( Pr



≥



pb )



1. For test when pwftest >pb



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Page 56 of 65 PI =



q Pr − pwfs



qb = PI ( pr − pb ) qo max = qb +



PI × pb 1.8



Points on IPR curve For pwf > pb : qo = PI ( pr − pwf ) For pwf < pb : qo = qb + ( qo max



2   pwf   pwf   − q b ) × 1 − 0.2   − 0.8      pb   pb    



2. For test when pwftest< pb q



PI =



2  pwf   pwf   pb  ( pr − pb ) + 1 − 0.2   − 0.8    1.8   pb   pb     qb = PI ( pr − pb )



qo max = qb +



PI × pb 1.8



Points on IPR curve For pwf > pb : qo = PI ( pr − pwf ) For pwf < pb : ( qo max



2   pwf   pwf   − qb ) × 1 − 0.2   − 0.8      pb   pb    



Where: qo= flow rate (B/D) qb= flow rate at bubblepoint (BD) pb= bubblepoint pressure (psi) qomax= maximum flow rate (Vogel or combination) (B/D) PI= Productivity Index (B/D/psi)



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6.1.4 Jones IPR pr − pwfs = aq 2 + b  2.30 × 10 pr − pwfs =   h p2rw 



− 14



AOF =



    re      µ o Bo ln 0.472  r   + s    w     q2 +  q    7.08 × 10 − 3 kh     



βBo2ρ 



− b ± b 2 + 4 a ( pr − 0 ) 2a



Where,  2.30 × 10 −14 βB 2ρ  o  2 a= q + 2   h p rw       re      µ o Bo ln0.472   + s    rw       b =  q 7.08 × 10 − 3 kh     q = flow rate (B/D) pr = average reservoir pressure (shut-in BHP) (psi) pwfs = flowing BHP at sandface (psi)



β = turbulence coefficient (ft-1) β=



2.33 × 10 10 k 1. 201



( after Katz )



Bo = formation volume factor (res bbl/STB)



ρ = fluid density (lbm/ft3) hp = perforated interval (ft)



µo = viscosity (cp) re = drainage radius (ft) rw = wellbore radius (ft) S = skin factor (dimensionless) k = permeability (md) a = turbulence term



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Page 58 of 65 b = darcy flow term 6.2 Gas IPR Equations 6.2.1 Darcy's Law (Gas) q=



2 703 × 10 −6 kh( pr2 − pwfs



 r  3  µ T Z ln  e  − + s    rw  4 



Where: q = flow rate (Mcf/D) k = permeability (md) h = net vertical thickness (ft) pr = average formation pressure (shut-in BHP) (psia) pwfs = sandface flowing BHP (psia) µ = viscosity (cp) T = temperature (°R) Z = supercompressibility (dimensionless) re = drainage radius (ft) rw = wellbore radius (ft)



S = skin factor (dimensionless) 6.2.2 Jones' Gas IPR (General Form) 2 pr2 − pwfs = aq 2 + bq



  r   1.424 × 10 3 µ TZ ln 0.472 e  + s  rw   3.16 × 10 βγ g TZ 2   q + q = 2 kh h p rw − 12



2 pr2 − pwfs



AOFP =



− b ± b 2 + 4a( pr2 ) 2a



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Where: 3.16 × 10 −12 βγ g TZ a= h p2 rw   r   1.424 × 10 3 µ TZ ln 0.472 e  + s  rw     b= kh q = flow rate (Mcf/D) a = turbulence term b = darcy Flow term p r = reservoir pressure (shut-in BHP) (psia) pwfs = sandface flowing BHP (psia)



β = turbulence coefficient (ft-1) β=



2.33 × 10 10 k 1. 201



γg= gas specific gravity (dimensionless) T = reservoir temperature (°R) hp= perforated interval (ft)



µ = viscosity (cp) re = drainage radius (ft) rw = wellbore radius (ft) 6.3 Backpressure Equation



(



q g = c pr2 − pwfs



)



n



Where: c=



703 × 10 −6 kh  r  3  µ TZ ln  e  − + s    rw  4 



n = 0.5 qg = flow rate (Mcf/D) k = permeability (md) h = net vertical thickness (ft) DOWELL CONFIDENTIAL



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p r = average formation pressure (shut-in BHP) (psia) pwfs = sandface flowing BHP (psia)



µ = viscosity (cp) T = temperature (°R) Z = supercompressibility (dimensionless) re = drainage radius (ft) rw = wellbore radius (ft) S = skin factor (dimensionless) 6.4 Transient Period Equations 6.4.1 Time to Pseudosteady State  φµct re2   tstab = 948  k  Where:



φ = porosity (fraction) µ = viscosity (cp) ct = total system compressibility (psi-1) re = drainage radius (ft) k = permeability (md) tstab = time for pressure transient to reach re (hr) 6.4.2 Oil IPR (Transient) qo =



(



kh pr − pwfs



)



  kt    162.6 µ o Bo log − 3 . 23 + 0 . 87 S  2   φµct rw  



Where: k = permeability (md) h = net vertical thickness (ft)



µ = viscosity (cp) Bo = formation volume factor (res bbl/STB) t = time of interest; t 0). If something occurs so that length extension stops, then one or both of the other variables, ∆p or ∆h must increase (that is, pressure must increase faster or fracture height must grow). If the fracture is well contained, then pressure must increase. This behavior is termed type III behavior. Refer to Fig 1. Type III behavior, with a slope of 1 indicates restricted extension at the tip. The most common occurrence of this is when the pad volume has become depleted and proppant reaches the fracture tip, arresting extension. This is called a tip screenout. A proppant bridge resulting from slurry dehydration due to natural fissures or height growth will also cause type III behavior. When a fracture grows out of zone into a formation with greater closure stress, the fracture “pinches down” at the boundary between the zones. This width restriction can cause proppant to bridge, but allow fluid to pass, dehydrating the slurry remaining in the main fracture. Once the slurry dehydrates sufficiently, a plug is formed. The plug cannot be moved down the fracture. In addition to proppant bridging, restricted extension and type III behavior can occur from the buildup of excessive fluid-loss additives in the pad. This causes a restriction at the tip and penetration into a higher stress region because of pore pressure gradients from prior production or because of lithology changes (that is, limited dimensions of lenticular or channel sands). Calibration treatments are useful to identify these causes for restricting fracture penetration. Refer to Fig. 1. A slope greater than 1 indicates that the restriction is closer to the wellbore. For instance, a wellbore screenout shows up as a near vertical line on the plot. Restrictions farther from the well will have slopes closer to 1. The approximate distance to the bridge can be calculated using Eq. 1.



dr =



qE h 2∆ p / ∆ t



Where: dr



= distance to restriction (ft)



q



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= Modulus of elasticity, Young's Modulus



h



= fracture height (ft)



∆p /∆t



= rate of pressure increase (psi/min).



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Eq. 1 assumes a constant fracture height, that the bridge is stationary, and calculates the maximum distance to the restriction. This calculation can then be used for designing future fracture treatments. A near-wellbore bridge is likely due to natural fissures, height growth or a slug of high concentration or proppant polymer. A bridge at the tip may be caused by pad depletion, improper fracture design or fluid problems.



Type IV Behavior Refer to Fig. 1. Type IV behavior, a negative slope, is an indication of rapid, unrestricted height growth. The radial-type fracture exhibits this response as well as a fracture that breaks through any confining barriers. If the fracture grows vertically through confining barriers into a zone of lower closure stress, unrestricted height growth will occur. The relatively overpressured fracture entering the low stress zone grows rapidly into the zone, increasing fracture volume and fluid loss. As the pressure decreases, the fracture in the intermediate zone may close. However, proppant bridging at the boundary of the main zone and the confining barrier causes slurry dehydration in the main fracture. Unrestricted height growth accelerates the process and a screenout results soon after, even at low proppant concentrations. The slurry dehydration, decreasing width and height-growth can be significantly reduced by placing a relatively impermeable mixture of fluid-loss additives (100 to 300 mesh) between the pad and the proppant stages. The DIVERTAFRAC* Service, INVERTAFRAC* Service, or both services can also be used. These techniques will form an impermeable bridge at the pinch-point. Foam fracturing fluids can also retard height-growth because of the yield stress for these fluids. The yield stress permits a pressure gradient to be developed which is proportional to the yield stress and inversely proportional to the width which is very small at the pinch-point. Type IV behavior may also be seen from the beginning of a fracture treatment. This indicates no height-confinement, and that the fracture is expanding rapidly. This is not as catastrophic as declining net pressure late in the treatment. However, future fracture designs should incorporate a fracture model (KGD, radial) for an unconfined-height fracture.



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Fig. 1. Slope interpretation for the Nolte-Smith plot. 2.1.2 In-Situ Stress Requirements The in-situ stress requirements for confined height-growth and to keep natural fissures from opening are very significant. The example in Fig. 2 indicates for a net pressure of 1500 psi, the stress contrast in the vertical direction must exceed 1500 psi and in the horizontal direction must exceed 1200 psi. Stress contrasts of these magnitudes cannot be assumed to occur for most reservoirs. Therefore, effective fracturing using normal practices cannot be assumed to occur for most reservoirs.



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Fig. 2. Example of required stress contrasts. 2.1.3 References Comprehensive discussions of injection pressure analysis techniques are provided in the following literature. Reservoir Stimulation, Chapter 7, Economides, M.J., and Nolte, K.G. (eds.), Schlumberger Educational Services (1989). A Practical Companion to Reservoir Stimulation, Chapter D, Economides, M.J., Schlumberger Educational Services (1991). Recent Advances in Hydraulic Fracturing, Chapter 14, Gidley, J.L., Holditch, S.A., Nierode, D.E., Veatch, R.W. (eds.), SPE Monograph Volume 12, Society of Petroleum Engineers (1989). Ayoub, J.A., Brown, J.E., Barree, R.D. and Elphick, J.: “Diagnosis and Evaluation of Fracturing Treatments,” paper SPE 20581. 2.2 Pressure Decline Analysis The analysis of the fracture after pumping allows the characterization of fracture geometry and the determination of the closure pressure, leakoff coefficient, and fracturing fluid efficiency. DOWELL CONFIDENTIAL



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2.2.1 References Comprehensive discussions of pressure decline analysis techniques are provided in the following literature: Reservoir Stimulation, Chapter 7, Economides, M.J., and Nolte, K.G. (eds.), Schlumberger Educational Services (1989). A Practical Companion to Reservoir Stimulation, Chapter D, Economides, M.J., Schlumberger Educational Services (1991). Recent Advances in Hydraulic Fracturing, Chapter 14, Gidley, J.L., Holditch, S.A., Nierode, D.E., Veatch, R.W. (eds.), SPE Monograph Volume 12, Society of Petroleum Engineers (1989). 2.3 Fracture Height Prediction and Post-Treatment Measurements Fracture height prediction is based on the prediction and measurement of rock properties in the layer above and below the target zone. These properties, properly treated, result in the prediction of the vertical propagation of the fracture. Posttreatment measurements including temperature logs, radioactive logs (in conjunction with radioactive materials), and sonic logs allow the estimation of the fracture height. 2.3.1 Sonic Logs Sonic waveforms are sensitive to the presence of fractures, even in cased-hole. In hard formations, conventional monopole sonic tools such as the Schlumberger Array-Sonic* fullwave sonic velocity tool or even the Long-Spaced Sonic tool will measure a shear component and can be used to detect fractures. In soft formations, the shear component is absent from monopole sonic waveforms and a dipole sonic tool (Schlumberger DSI* tool) is required to measure the shear wavetrain. The technique consists of acquiring a sonic waveform VDL before the fracturing treatment and another after the fracturing treatment. The difference is usually very clear. In obvious cases, a single pass may be sufficient. One drawback is the limited depth of investigation (usually around a foot). Consult Wireline engineers to determine the tool best suited for the area. 2.3.2 References Comprehensive discussions of fracture height-prediction techniques are provided in the following literature. Reservoir Stimulation, Chapter 10, Economides, M.J., and Nolte, K.G. (eds.), Schlumberger Educational Services (1989). A Practical Companion to Reservoir Stimulation, Chapter B, Economides, M.J., Schlumberger Educational Services (1991). *



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3 Treatment Performance Monitoring Treatment performance monitoring involves data acquisition, and permits estimation of the results of the fracturing treatment in its geologic setting. There are two purposes for treatment performance monitoring. 1.



The first purpose is to assess the fracture properties (length and conductivity) achieved in the treatment against those prescribed initially by the client or derived in the design analysis.



2.



The second purpose is to provide the data which permits determination of the full-scale mechanical and permeability properties of the host medium for the treatment.



Fracture data is acquired during and immediately following the treatment execution and during well production and pressure build-up tests. Because the data acquisition and subsequent analysis are essentially independent for the two separate monitoring exercises, the opportunity is provided for checking the consistency of the models, assumptions and input data used separately in fracture engineering and reservoir engineering for the well. Noting that in each exercise, the data set is under-determined, (that is, there is less data than is needed to provide a unique identification of the parameter set describing the system), some effort may be required to reconcile the different models, the results obtained from them and the analytical procedures used in the two fields of practice. The time history of bottomhole treating pressure is the primary data set of the treatment data. Because different aspects of formation mechanical behavior are expressed in different stages of a treatment, a complete pressure history must be collected. For example, early in a treatment, fracture growth may involve transition from a radial to a confined fracture. That part of the pressure record contains unique information on formation height, providing an essential geometric scale in the data set. After shut-in, the pressure decline record contains information on stress barriers and the leak-off coefficient. Ideally, other data should be collected which provide a capacity to identify unique components of system performance. In a MultiFRAC* treatment, cross-flow between layers after shut-in is related directly to the compliance of the various layers. In comparison with the data needs for thorough analysis of pressure and other treatment data, those for well production and pressure build-up analysis have been well defined through consideration of the principles of inverse analysis. A comparable effort is required in treatment data set definition for treatment record analysis. 3.1 Inverse Analysis of Treatment and Production Data Records Inverse analysis is the technique by which a physical system is characterized from observations of its response to imposed perturbations (disturbances), using a simulator which represents the detailed behavior of the system. The technique was developed initially to characterize the thermomechanical properties of bodies under DOWELL CONFIDENTIAL



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extreme loading conditions, such as rocket nose cones under re-entry conditions. In its more general application, a system simulator and a search routine (or polytope) may be used to identify the values of a parameter set which minimize an error residual (or objective function) in a multi-variant parameter space. In structural mechanics, for example, the method is used to invert vibration records of frames to obtain the stiffness of individual members and of joints. In reservoir engineering, a pressure build-up record is inverted using a reservoir simulator and a suitable polytope to define formation properties of interest. The ZODIAC* software is an inverse analysis application using a suite of simulators driven by a polytope called “CONREG”. In the application of inverse analysis techniques to a treatment record, the purposes are to identify fracture length and conductivity, review the adequacy of the postulated setting model and recover improved data on the in-situ mechanical properties of the formation and its setting. If suitable constraints can be provided as inputs to the analysis, it may return a more reliable modelization of the medium, particularly on features not previously accounted for in the model. Estimates of formation mechanical properties, for example, may reflect the average conditions which operate on the in-situ scale rather than those obtained from non-representative laboratory tests on disturbed specimens. The output from the inverse analysis provides an improved set of setting characterization data, and may lead to significant modification of the setting modelization, formation constitutive model and fracture simulation procedures used in subsequent designs of treatments in adjacent wells in the formation. 3.1.1 Fracture Characterization Using the ZODIAC Software The ZODIAC software contains a general purpose pressure transient analysis model that can be used to interpret the transient behavior of unfractured, horizontal, and vertically fractured wells. Pressure transient testing of oil and gas wells is considered by most reservoir engineers to be one of the more reliable means of characterizing the production characteristics of a reservoir. Pressure transient tests of unfractured wells can be used to obtain estimates of the average conductivity of a reservoir, any near well flow impairment and interference with adjacent wells. Pressure transient testing is also commonly used to evaluate the effectiveness of hydraulic fracturing treatments. A significant limitation of some of the earlier fractured well pressure transient analysis models was that there were so many limiting assumptions used in the development of the interpretation models that the models often bore little resemblance to the types and shapes of vertical fractures that were actually being created. This limitation, together with the limitations of the models to consider the practical, non-ideal reservoir characteristics such as permeability, anisotropy and boundary effects, and the fracture properties of fracture face skin and storage, often resulted in the under-estimation of the actual fracture lengths. *



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The new fractured well interpretation models that are being added to the ZODIAC software will provide a means of obtaining more realistic estimates of the propped fracture dimensions and conductivity than has been possible previously. The practical analysis features that have been added to the ZODIAC software that can be used to more properly interpret the pressure transient behavior of vertically fractured wells includes: • the effects of spatially-variable fracture height •



fracture width effects



•



the effect of conductivity distributions



•



the effects of fracture face skin damage



•



fracture storage effects



•



the effects of reservoir permeability anisotropy



•



finite reservoir boundary effects.



The analysis features of fracture storage and boundary effects are not operational in the current version of the ZODIAC software but have been fully developed and will be available in the next engineering code release. The pressure transient interpretation models in the ZODIAC software can be used to detect and generally quantify each of these reservoir and fracture characteristics. The summary that follows addresses each of the new features that are available in the ZODIAC software to obtain a better interpretation of the pressure transient behavior of vertically fractured wells and to more properly characterize the created fracture dimensions and conductivity. 3.1.1.1 Fracture Storage The general pressure transient analysis models that have been developed for the ZODIAC software include fracture flow models that consider (or neglect) the storage effects of the vertical fracture due to the contrast in the hydraulic diffusivities of the reservoir and the propped fracture. The effects of fracture storage are minimal for moderate- to high-dimensionless-conductivity fractures at early time; the effects of fracture storage on the pressure transient behavior can be observed for much of the duration of the transient test period. When referring to the fracture storage effect, it is most convenient to use the dimensionless hydraulic diffusivity to quantify the pressure transient behavior of the system, since the dimensionless hydraulic diffusivity and the dimensionless fractureconductivity-height product are the only two fracture parameter groups that are necessary to parameterize the pressure distribution in the fracture as a function of time and space. The fracture pressure distribution is of course a function of the reservoir properties, which are related to the fracture flow solution through the fracture flux distribution. A comparison of the pressure transient behavior of a highconductivity fracture (CfD = 300) with the finite-conductivity fracture models that DOWELL CONFIDENTIAL



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neglect or consider the fracture storage effects is shown in Fig. 3. A similar comparison is shown in Fig. 4 for a low-conductivity fracture (CfD = 3). The fracture storage has minimal effect on the pressure transient behavior of the low-conductivity fracture after a dimensionless time of about 10-3. However, the pressure transient behavior of the high-conductivity fracture is observed to be significantly affected by the contrast in the hydraulic diffusivities of the reservoir and the fracture as late a dimensionless time of 10-2. Using a fracture interpretation model that neglects the fracture storage effects will tend to produce estimates of fracture conductivity that are too high and will result in under-estimation of the actual fracture length. 3.1.1.2 Fracture Face Skin Damage The current version of the ZODIAC software can be used to quantify fracture face skin damage effects on the pressure transient behavior of a finite conductivity fracture using a model that considers the fracture storage effects to be negligible. The next engineering code release of the ZODIAC software will include a finiteconductivity fracture interpretation model that considers the fracture storage effects of the system. Fig. 5 shows the effect of fracture face skin damage on the pressure transient behavior of a moderate-conductivity fracture (CfD = 10) with fracture storage. The corresponding comparison of the fracture face skin damage effects on a finite-conductivity fracture (same dimensionless conductivity; fracture storage effects considered to be negligible), is shown in Fig. 6. A similar set of comparisons are shown in Fig. 7 and Fig. 8 for a low-conductivity (CfD = 1) fracture. These comparisons illustrate that each of these factors (fracture face skin and storage) can significantly affect the interpretation of the pressure transient behavior of finiteconductivity fractures, both individually and in combination with each other. 3.1.1.3 Variable Fracture Conductivity The pressure transient behavior of a finite-conductivity fracture with spatially varying fracture conductivity is shown in Fig. 9 for three fracture conductivity distributions, in which, the fracture has high average dimensionless conductivity. Little noticeable effect is observed for the spatially variable fracture conductivity for the practical range of transient test times. The fracture conductivity distributions used in this comparison were uniform, linearly varying, step profile dimensionless fracture conductivity distributions. The dimensionless fracture conductivity for the variable conductivity distribution schemes were specified as equal to 500 at the wellbore and 0 at the fracture tip. The step profile used in this comparison consisted of 50% reductions in the dimensionless fracture conductivity at each quarter of the fracture length. The corresponding dimensionless fracture conductivity distribution that was used in this comparison for the step profile was CfD = 500 for the first quarter of the fracture length, CfD = 250 for the second quarter, CfD = 125 for the third quarter, and a CfD = 62.5 for the last quarter of the fracture length (nearest the fracture tip).



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A similar comparison is shown in Fig. 10 for a finite-conductivity fracture with a moderate average fracture conductivity (CfD). A similar set of conductivity profiles were used in this case except that the specified dimensionless fracture conductivity equaled 10. In this case, the effects of a spatially variable fracture conductivity distribution are more significant over the range of transient times of interest. For even lower average dimensionless conductivity fractures, the effect of the spatial variation in the fracture conductivity becomes more pronounced. 3.1.1.4 Reservoir Permeability Anisotropy Fig. 11 and Fig. 12 show the dimensionless and dimensional pressure transient and derivative behaviors of a finite-conductivity fracture with a uniform fracture conductivity of 400,000 md-ft in an anisotropic reservoir, with various levels of reservoir permeability anisotropy. The fracture and reservoir parameters used (xf = 400 ft, kmax = 1.0 md) correspond to a dimensionless fracture conductivity of 1000 in an isotropic reservoir with kx = ky = 1.0 md. Fig. 13 and Fig. 14 show the dimensionless and dimensional pressure transient behaviors of a finite-conductivity fracture with uniform fracture conductivity of 2000 md-ft. The same reservoir and fracture parameters are used in this case as in the previous example. In these examples, the dimensionless fracture conductivity for the isotropic reservoir case is equal to 5.0. The anisotropic reservoir model is available in the current release of the ZODIAC software. 3.1.1.5 Finite Reservoirs The next engineering code development release of the ZODIAC software will have several finite reservoir solutions available for fractured wells. The finite reservoir solutions that will be available for the analysis of vertically fractured wells in finite reservoirs will be the models for a fractured well centered in a closed or constant pressure circle, and a fractured well that can be off-centered in a closed rectangle. Examples of the types of finite reservoir solutions that will be available in the next release of the ZODIAC software are shown in Fig. 15, Fig. 16, and Fig. 17.



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Fig. 3. High-conductivity fracture comparison.



Fig. 4. Low-conductivity fracture comparison.



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Fig. 5. Fracture face skin damage, moderate-conductivity fracture.



Fig. 6. Fracture face skin damage, finite-conductivity fracture.



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Fig. 7. Fracture face skin damage comparison, low-conducitivy fracture.



Fig. 8. Fracture skin damage comparison, low-conductivity fracture.



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Fig. 9. Finite-conductivity fracturecomparison, high average dimensionless conductivity.



Fig. 10. Finite-conductivity comparison, moderate average fracture conductivity.



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Fig. 11. Finite-conductivity comparison, uniform fracture conductivity 4000,000 md-ft.



Fig. 12. Finite-conductivity comparison, uniform fracture conductivity 4000,000 md-ft.



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Fig. 13. Finite-conductivity comparison, uniform fracture conductivity 2000 md-ft.



Fig. 14. Finite-conductivity comparison, uniform fracture conductivity 2000 md-ft.



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Fig. 15. ZODIAC software examples.



Fig. 16. ZODIAC software examples.



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Fig. 17. ZODIAC software examples.



4 Production Evaluation The inference of fracture length from the reservoir response is very sensitive to uncertainties such as inferred skin, formation permeability, and fracture conductivity. For a 5% change in skin, the minimum length change is 30%. The ability to infer a representative length diminishes rapidly for a dimensionless fracture conductivity less than two. More significant are the limitations of constant, homogeneous, and isotropic reservoir permeability and homogeneous fracture conductivity. These limitations produce inferred lengths which can be substantially less than the actual length. Further, these effects are cumulative and can result in the inferred length being only a small fraction of the actual case, or more importantly, the production much less than anticipated and a false indication of treatment failure. Except for anisotropic permeability, all the limitations can be diagnosed or quantified by standard field measurements and analyses. Special testing of oriented core can identify matrix-permeability anisotropy and provide a relatively accurate assessment of permeability variations with depth. Reservoir analysis typically assumes constant, isotropic, and homogeneous conditions for the reservoir and fracture conductivity. Heterogeneous reservoir and conductivity effects will cause the well production to be less than expected from the DOWELL CONFIDENTIAL



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assumption of homogeneous properties. Heterogeneous reservoir conditions may give a false indication of fracturing treatment failure. In the case of constant, isotropic, and homogeneous conditions, evaluation can be routinely applied by district level engineers with standard training and CADE functionality. The evaluation of well performance is a comparison of predicted versus actual performance. The FORECAST module in the FracCADE* software may be used for production prediction. User information for the FORECAST module is provided in the FracCADE Users Manual. In the case of heterogeneous reservoir and conductivity effects, accurate evaluation will require proficient use of the most advanced techniques and will require specially trained experts within the area or region. The evaluation may require several weeks to months for completion. 4.1 References Comprehensive discussions of production analysis techniques are provided in the following literature. Reservoir Stimulation, Chapter 11, Economides, M.J., and Nolte, K.G. (eds.), Schlumberger Educational Services (1989). A Practical Companion to Reservoir Stimulation, Chapter F, Economides, M.J., Schlumberger Educational Services (1991). Recent Advances in Hydraulic Fracturing, Chapter 15 and Appendix K, Gidley, J.L., Holditch, S.A., Nierode, D.E., Veatch, R.W. (eds.), SPE Monograph Volume 12, Society of Petroleum Engineers (1989).



*



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DataFRAC SERVICE 1 Introductory Summary............................................................................................................. 6 1.1 Closure Test......................................................................................................................... 7 1.1.1 Closure Test in a Permeable Zone ............................................................................. 7 1.1.2 Closure Test in a Nonpermeable Zone....................................................................... 9 1.2 Calibration Test.................................................................................................................... 9 1.3 Applications........................................................................................................................ 10 2 Design ..................................................................................................................................... 11 2.1 Preparatory Engineering .................................................................................................... 11 2.1.1 Breakdown/Diversion Treatment .............................................................................. 11 2.1.2 Preliminary Fracture Design ..................................................................................... 11 2.1.3 Fracture Height......................................................................................................... 11 2.1.4 Wellbore Logging...................................................................................................... 12 2.1.4.1 Temperature and Gamma-Ray Logs ............................................................. 12 2.1.4.2 Fracture-Height Logs ..................................................................................... 13 2.1.5 Perforating ................................................................................................................ 13 2.1.5.1 Wellbore Restrictions ..................................................................................... 13 2.1.5.2 Perforation Phasing ....................................................................................... 14 2.1.5.3 Perforation Size ............................................................................................. 14 2.2 Closure Test....................................................................................................................... 15 2.2.1 Fluid Selection .......................................................................................................... 15 2.2.2 Injection Rates and Number of Steps ....................................................................... 15 2.2.3 Step Duration............................................................................................................ 15 2.2.4 Flow-Back Rate ........................................................................................................ 16 2.3 Calibration Test.................................................................................................................. 17 2.3.1 Fluid Selection .......................................................................................................... 17 2.3.1.1 Foam.............................................................................................................. 17 2.3.2 Fluid Volume............................................................................................................. 17 2.3.3 Fluid Break-Time ...................................................................................................... 18 DOWELL CONFIDENTIAL



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2.3.4 Fluid-Loss Additives ..................................................................................................18 2.3.5 Duration of Pressure Decline ....................................................................................18 2.4 Special Considerations in the DataFRAC Design...............................................................18 2.4.1 The Influence of Wellbore Fluid ................................................................................18 2.4.2 Prepad.......................................................................................................................18 2.4.3 Closure Pressure less than Hydrostatic Pressure.....................................................19 2.4.4 Post-Job Wireline Surveys ........................................................................................19 2.5 Terminology........................................................................................................................19 2.5.1 Fracture Extension Pressure.....................................................................................19 2.5.2 Initial Shut-in Pressure ..............................................................................................19 2.5.3 Closure Pressure ......................................................................................................19 2.5.4 Rebound Pressure ....................................................................................................19 2.6 Equipment Requirements ...................................................................................................20 2.6.1 Monitoring Equipment ...............................................................................................20 2.6.2 Pumping Equipment..................................................................................................20 2.6.3 Pressure Measuring Equipment................................................................................20 2.6.3.1 Surface Measurement Methods .....................................................................20 2.6.3.2 Bottomhole Pressure Gauge Measurement ...................................................22 2.6.4 Treating Equipment...................................................................................................23 2.6.5 Flowback Equipment.................................................................................................23 2.6.5.1 Magnetic Flowmeters .....................................................................................23 2.6.5.2 Turbine Flowmeters........................................................................................23 2.6.5.3 Chokes and Gate Valves................................................................................23 3 Execution ................................................................................................................................24 3.1 Pre-Performance Guidelines ..............................................................................................24 3.2 Closure Test .......................................................................................................................27 3.2.1 Step-Rate Phase.......................................................................................................27 3.2.2 Flowback Phase........................................................................................................32 3.2.2.1 Flow Control ...................................................................................................32 3.2.2.2 Flowmeters.....................................................................................................34 3.2.3 Closure Test Modifications........................................................................................34 DOWELL CONFIDENTIAL



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3.3 Calibration Test.................................................................................................................. 35 3.3.1 Injection Phase ......................................................................................................... 35 3.3.2 Pressure-Decline Phase ........................................................................................... 36 3.3.3 Contingency Plans.................................................................................................... 36 4 Evaluation............................................................................................................................... 36 4.1 Closure Test Analysis ........................................................................................................ 37 4.1.1 Step Rate  The BHP-Versus-Rate Plot ................................................................. 37 4.1.2 Flowback  The BHP-Versus-Time Plot.................................................................. 37 4.1.3 Confirmation of Closure Pressure............................................................................. 38 4.1.4 Rebound Pressure.................................................................................................... 40 4.2 Calibration Injection for Fracture Geometry ....................................................................... 40 4.2.1 Elastic Fracture Compliance..................................................................................... 41 4.2.2 Pressure During Pumping......................................................................................... 43 4.2.2.1 Fluid Flow and Pressure in Fracture .............................................................. 43 4.2.2.2 Nolte-Smith Plot and Evolution of Pressure During Pumping ........................ 45 4.2.3 Deviations from Ideal Geometry ............................................................................... 46 4.2.3.1 Height Growth ................................................................................................ 46 4.2.3.2 Fissures ......................................................................................................... 47 4.2.3.3 T-Shape Fracture........................................................................................... 48 4.2.4 Pressure Capacity .................................................................................................... 49 4.2.5 Near-Wellbore Restriction......................................................................................... 50 4.2.6 Fracturing Pressure Interpretation Summary ........................................................... 53 4.2.6.1 Example of Radial Fracture ........................................................................... 54 4.2.6.2 Simulation of Pressure During Pumping and Decline .................................... 54 4.3 Calibration Decline for Fluid-Loss Behavior ....................................................................... 56 4.3.1 Review of Decline Analysis....................................................................................... 56 4.3.2 Volume Function g.................................................................................................... 58 4.3.3 Fluid Efficiency.......................................................................................................... 59 4.3.4 Decline Function G ................................................................................................... 61 4.3.5 Non-Ideal Behavior ................................................................................................... 64 4.3.5.1 Change in Fracture Penetration After Shut-in................................................ 64 DOWELL CONFIDENTIAL



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4.3.5.2 Height Growth ................................................................................................65 4.3.5.3 Pressure-Dependent Leakoff .........................................................................66 4.3.5.4 Spurt...............................................................................................................69 4.3.5.5 Closure Pressure Change ..............................................................................69 4.3.5.6 Compressible Fluids.......................................................................................71 4.3.6 Fluid Efficiency Based on Pressure Analysis ............................................................72 4.3.7 Decline-Analysis Procedure ......................................................................................73 4.3.8 Steps to Correct Decline Analysis Using the FracCADE Software............................75 4.3.8.1 The DataFRAC Software................................................................................76 4.3.8.2 G-plot Interpretation by the DataFRAC Software ...........................................77 4.3.8.3 Modulus, Height or Fracture Toughness Calibrations ....................................77 4.3.8.4 The β Ratio.....................................................................................................78 4.3.9 Post Proppant Fracture Analysis...............................................................................80 4.3.10 References..............................................................................................................81 FIGURES Fig. 1. The effect of proppant-pack damage and fracture length on fracture NPV. ......................6 Fig. 2. Fracture extension pressure (unequal time steps). ...........................................................7 Fig. 3. The typical closure test......................................................................................................8 Fig. 4. The G-plot (idealized). .....................................................................................................10 Fig. 5. Channel restriction at the wellbore. .................................................................................13 Fig. 6. The relation of perforation diameter and proppant concentration. ..................................14 Fig. 7. The effects of differing flowback rates. ............................................................................16 Fig. 8. The change in surface pressure during closure in deep, hot wells..................................21 Fig. 9. Hydrostatic head changes during closure. ......................................................................22 Fig. 10. The DataFRAC Service rig-up when pumping conductive fluids. ..................................25 Fig. 11. The DataFRAC Service rig-up when pumping nonconductive fluids. ............................26 Fig. 12. Friction pressure of water in the tubing and casing. ......................................................28 Fig. 13. Friction pressure of water in the annulus.......................................................................29 Fig. 14. Friction pressure of brine in the tubing and casing........................................................29 Fig. 15. Friction pressure of brine in the annulus. ......................................................................30 Fig. 16. Friction pressure of diesel in the tubing and casing. .....................................................30 Fig. 17. Friction pressure of diesel in the annulus. .....................................................................31 Fig. 18. Flow rate versus differential pressure in perforations....................................................31 Fig. 19. Flowback test (after Nolte, 1982/1994)..........................................................................38 Fig. 20. Effect of closure on BHP versus square root of t and G- plots. .....................................39 Fig. 21. Rebound pressure; lower bound of closure pressure....................................................40 Fig. 22. Analogy of a pressurized crack to a pre-loaded spring. ................................................42 Fig. 23. Evolution of fracture geometry and pressure during pumping.......................................45 Fig. 24. Pressure and width for height growth through barriers (after Nolte, 1989)...................46 DOWELL CONFIDENTIAL



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Fig. 25. Fig. 26. Fig. 27. Fig. 28. Fig. 29. Fig. 30. Fig. 31. Fig. 32. Fig. 33. Fig. 34. Fig. 35. Fig. 36. Fig. 37. Fig. 38. Fig. 39. Fig. 40. Fig. 41. Fig. 42. Fig. 43. Fig. 44. Fig. 45. Fig. 46.



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Pressure and width for opening natural fissures (after Nolte, 1989)............................ 47 Pressure and width for T-shape fracture (after Nolte, 1989)........................................ 48 Definition of pressure capacity from in-situ stresses..................................................... 50 Stress state within the entrance of deviated well or stress. .......................................... 51 Mohr circle of deviated well or stress. ........................................................................... 52 Nolte-Smith plot of fracturing pressure. ........................................................................ 53 Net pressure with radial fracture (after Smith et al. 1987). .......................................... 54 Measured and simulated net pressure: opening natural fissures (after Nolte, 1982). . 55 Example of fracturing-related pressures (after Nolte, 1982). ........................................ 56 Schematic for fracture area and time............................................................................ 57 Dimensionless volume function for fracture closure (after Nolte, 1986)....................... 59 Efficiency from closure time for no proppant, no spurt loss during pumping and other ideal assumptions given in Section 4.3.1 (after Nolte, 1986). ............................. 60 Conceptual response of pressure decline versus Nolte time-function (after Castillo, 1987). .................................................................................................... 62 Penetration change during shut-in (after Nolte, 1990). ................................................. 65 Diagnostic for height growth from decline data (after Nolte, 1990)............................... 66 Diagnostic for stress sensitive fissures from injection and decline (after Nolte, 1990). 67 Decline analysis for filtrate and reservoir control leakoff (after Nolte, 1993)................ 68 Stress change during injection/shut-in for Cc (after Nolte et. al., 1993)......................... 70 Relative volume change of gas (after Nolte et. al., 1993). ........................................... 72 Decline analysis using “¾” rule (after Nolte, 1990). ...................................................... 74 Pressure and flow rate in fracture before and after shut-in (after Nolte, 1986)............ 79 Diagnostic for closing on proppant from decline data (after Nolte, 1990). ................... 80 TABLES



Table 1. Table 2. Table 3. Table 4. Table 5.



Approximate Choke Settings For Flowback Of Oil-Base Fluids (Sg = 0.7) .................. 33 Approximate Choke Settings for Flowback of Water-Base Fluids (Sg = 1.0)............... 34 Interpolated Values of α Over the Full Range of n....................................................... 58 Values of Decline Function "G" .................................................................................... 63 Correction Factors f c As Function Of ∆tD ...................................................................... 75



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1 Introductory Summary The DataFRAC* Service determines the in-situ parameters critical to optimum fracture treatment design. These parameters are specific to each formation and often to each well. Assumed or inaccurate parameter values can result in the following. • Premature screenout and reduced fracture penetration caused by pad fluid depletion. •



Unpropped fracture, increased damage to proppant-pack conductivity and increased treatment cost because of excessive pad volume.



Both outcomes result in reduced net present value (NPV), illustrated in Fig. 1.



Fig. 1. The effect of proppant-pack damage and fracture length on fracture NPV. (THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY.) The DataFRAC Service typically consists of two tests  a closure test and a calibration test.



*



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Section 700.1 May 1998 Page 7 of 81



1.1 Closure Test The closure test determines closure pressure  the minimum in-situ rock stress. Accurate determination of closure pressure is important because all fracture analysis is referenced from it. Closure pressure is also used for proppant selection. The closure test is recommended as one of the initial procedures of any field stimulation operation. Performance of a valid closure test • ensures the zone has been fractured (a necessary condition for valid performance of other tests) •



provides upper and lower bounds for determination of the closure pressure



•



defines the required range of pump rates for extending a fracture in the zone.



1.1.1 Closure Test in a Permeable Zone The closure test in a permeable zone is a step-rate/flowback procedure. A Newtonian fluid is injected at an increasing rate until fracture extension occurs. A pressure versus rate plot will show two distinct slopes, the intersection of which indicates fracture extension pressure (Fig. 2). The change in slope in is a result of the different pressure responses for matrix leakoff and fracture extension at the higher rate. This pressure is normally 50 to 200 psi greater than closure pressure because of fluid friction in the fracture and fracture toughness.



Fig. 2. Fracture extension pressure (unequal time steps). (THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY.) DOWELL CONFIDENTIAL



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Another indication of fracture extension pressure comes from a bottomhole pressure versus time plot and is illustrated in Fig. 3. The pressure steps above fracture extension pressure have squared shoulders compared to the rounded shoulders characteristic of matrix leakoff.



Fig. 3. The typical closure test. (THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY.) Pumping continues for five to ten minutes after fracture extension. The well is then flowed-back at a constant rate. Flowback is started immediately after the final step and is held constant until pressure has fallen to about 200 psi above the initial wellbore pressure. The pressure response will show a distinct reversal in curvature once closure has occurred (Fig. 3), indicating a change of fluid withdrawal from the open fracture to withdrawal through the matrix. The rebound pressure after shut in serves as a lower bound to closure pressure. Perforation friction pressure is another important parameter that is determined from the step-rate/flowback test. At shut-in, the immediate bottomhole pressure drop is the pressure loss in the perforations during the last stage of the step-rate test. The pressure loss will give an indication of potential wellbore problems, usually unopened perforations. Reperforating should be considered if the pressure loss is unacceptable. The closure pressure is determined by quantitative analysis of bottomhole pressure versus time using the Pressure Analysis and DataFRAC modules in the FracCADE* software.



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Section 700.1 May 1998 Page 9 of 81



The closure pressure may also be determined from a shut-in/decline test by analysis of a square-root plot. However, the shut-in/decline method does not provide a definitive indication of the closure pressure and is not the preferred method. 1.1.2 Closure Test in a Nonpermeable Zone The closure test in a nonpermeable zone (shale) is an injection/shut-in procedure where a small quantity (tens of gallons) of a Newtonian fluid is injected at low rate. Pumping stops and an initial shut-in pressure is observed. Local stress is approximately equal to the initial shut-in pressure; therefore, net pressure is approximately equal to zero and the initial shut-in pressure is used to infer the stress. 1.2 Calibration Test The calibration test is an injection/shut-in/decline procedure. A viscosified fluid (without proppant) is pumped at proposed fracturing treatment rate. The well is then shut in and a pressure decline analysis is performed. The following critical design parameters are determined from the calibration test. • fracture half-length (xf) •



fracture width (w)



•



fracture height (hf)



•



fluid-loss coefficient (C)



•



Young's modulus (E)



•



fluid efficiency (η).



The injection test determines the type of fracture being created; Perkins-KernNordgren (PKN), Khristianovic-Geertsma-de Klerk (KGD), or Geertsma-de Klerk radial (RAD). Analysis of the net pressure versus time on a log-log scale (NolteSmith plot) determines the type of model (PKN, KGD, or RAD) to use for decline analysis. The injection test also serves as the pumping portion of the decline test. Pressure decline after shut-in is monitored and is analyzed using the Pressure Analysis, Decline Data and DataFRAC modules in the FracCADE software to determine the parameters listed above. The DataFRAC Service uses the G-plot for complete, consistent analysis. The G-plot (illustrated in Fig. 4) replaces the curve-matching method and can accentuate nonideal fracture behavior such as unrestrained height growth and extension after shut-in and closure. Analysis results from the DataFRAC module in the FracCADE software automatically update the fracture geometry simulator. The calculated net pressure is compared and recorded with the net pressure observed at shut-in. This dual analysis ensures a consistent set of parameters for the treatment design and indicates potential nonideal fracture behavior when a pressure match cannot be justified. DOWELL CONFIDENTIAL



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Fig. 4. The G-plot (idealized). (THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY) 1.3 Applications The DataFRAC Service is an expense to the client that is not incurred if generally available design data that is not specific to a particular well is used. However, this service can increase the NPV when it results in optimization of a treatment design. The DataFRAC Service can be routinely performed before all fracture treatments when the objective is to optimize the treatment design and resulting production. It is also an invaluable aid to assure the best possible treatment is performed in cases where information is limited. Some opportunities where the DataFRAC Service offers particular benefits are • pilot projects or test wells that are critical to future development plans •



wells that are considered typical to a field where designs are being tested to settle on an optimum



•



exploration wells that have no history on which to design a treatment with a high level of confidence



•



areas where fracture response is not as anticipated and the cause requires identification.



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2 Design 2.1 Preparatory Engineering The DataFRAC Service is mainly analytical in nature. Other sources of data will enhance the DataFRAC analysis. 2.1.1 Breakdown/Diversion Treatment Perform a breakdown/diversion treatment (for example, acid ballout) prior to performing a closure or calibration test to ensure that all perforations are open and that the formation has been broken-down. The initial shut-in pressure recorded on a breakdown/diversion treatment will be a very rough estimate of the closure pressure. 2.1.2 Preliminary Fracture Design The parameters important to the DataFRAC Service are discussed below. Fracture treatment design is provided in Treatment Design. Before performing the DataFRAC Service, a fracturing treatment should be designed using the best data available. Use the FracCADE software for the treatment design. The fluid type, expected pad volume and efficiency, fracture geometry, and net pressure will provide a reference for the same parameters that will be determined from the DataFRAC analysis. A preliminary fracture design will also help to identify unexpected or nonideal behavior during the closure and calibration tests. If the preliminary fracture design indicates that the fracture capacity will be exceeded (undesired height growth or opening of fissures), the DataFRAC Service will confirm that and will quantify the fracture capacity based on actual, rather than assumed pumping conditions. The subsequent fracture design can then be prepared with either more confidence that the fracture capacity will not be exceeded or that special techniques can be used to alleviate the problem. 2.1.3 Fracture Height Fracture height affects fracture volume in two ways: directly, and through its effect on width (determined by the fracture compliance). Accurate values for gross fractureheight (formation gross height) and leakoff height (formation net thickness) are critical to the DataFRAC analysis and to the ultimate success of the fracture design and execution. If these values cannot be selected with a comfortable degree of certainty prior to the fracture treatment, the need for the DataFRAC Service and wireline surveys (logs) becomes even more critical for stimulation success. The following methodology may be used to determine fracture height. • Select “apparent” barriers from logs. •



Perform the DataFRAC Service to verify that height and Young's modulus match with log-derived values. DOWELL CONFIDENTIAL



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Run pre- and post-job temperature logs or radioactive tracers and a gamma-ray log (or all) to identify the actual fracture height.



2.1.4 Wellbore Logging Pre- and postjob logs can give a starting point for height determination in the analysis. Prior to performing the DataFRAC Service, request that the appropriate wireline services be utilized to estimate fracture height (Gamma-Ray log, Sonic log), leakoff height (SP log, Porosity log), and Young's modulus (Sonic log). Request radioactive tracers for the calibration test. Request postfracture logs (Temperature log and Gamma-Ray log) for fracture height verification. 2.1.4.1 Temperature and Gamma-Ray Logs Temperature and gamma-ray logs are commonly used to determine fracture height. Gross fracture-height is commonly determined from lithology information. Leakoff height can be based on a porosity cut-off or gamma-ray/spontaneous potential (SP) deflection. Normally, the height of any zone with greater than 1/3 deflection from the shale base-line is considered leakoff height. Additional techniques to determine fracture height are provided in Reservoir Stimulation. During analysis, the following should be considered. 1.



Logs only detect radioactive material and temperature differences a few inches away from the wellbore.



2.



The fracture tends to be away from the wellbore outside the perforated interval.



3.



The formation must have both permeability and porosity to hold enough radioactive fluid for detection.



In the first consideration, wellbore fracture height may not be the same as the average height of the fracture because of deviated wellbore or zone, height growth into the barriers at the wellbore or horizontal fractures. The net pressure (during pumping) and a fracture simulator can give estimation of the average height. In the DataFRAC module, height and Young's modulus are altered to make the Fracture Geometry Sensitivity simulator (FGS) and the analysis (actual) net pressure match. When the net pressures are matched, the heights and modulus should match with those obtained from logs. If no match is obtained, then one of the sources may be incorrect. Shale barriers have very low permeability and porosity and will tend to “squeeze out” any fluid during fracture closure. A more permeable and porous zone above the shale will retain the fluid. A fracture may grow into this zone and the indication be discounted because the shale barrier doesn't show radioactivity or temperature change. This can also be missed if the wireline service company turns down the tool sensitivity when away from the zone of interest. Without an independent indication of fracture height, analysis is more difficult and may be less accurate. Analysis will be enhanced with the aid of logs. DOWELL CONFIDENTIAL



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Section 700.1 May 1998 Page 13 of 81



2.1.4.2 Fracture-Height Logs If a fracture-height log is available, use stress information from the log to limit net pressure and, therefore, fracture height in the design. This can often demonstrate the sensitivity of vertical fracture growth to pump rate and fluid rheology. Once sensitivity is established, the need for the DataFRAC service is apparent to pinpoint the critical design parameters and to calibrate the FGS simulator. 2.1.5 Perforating Perforating technique can have a significant effect on the execution and evaluation of the DataFRAC Service by affecting the breakdown and treating pressure. 2.1.5.1 Wellbore Restrictions Wellbore restrictions will mask the formation pressure response while pumping. The value for net pressure will be inaccurate because of a shift upward. Fracture model selection may be affected. During the fracturing treatment the proppant will erode the restrictions resulting in lower perforation friction pressure. A drop in perforation friction pressure may be interpreted (falsely) as fracture height-growth. Wellbore restrictions caused by improper or ineffective perforating techniques can cause a screenout. Restrictions can cause the fracture to extend in an area apart from the perforation tunnel, resulting in a significant increase in apparent perforation friction pressure (Fig. 5).



Fig. 5. Channel restriction at the wellbore. (THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY)



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2.1.5.2 Perforation Phasing Wells are commonly perforated with 0° phasing (perforations vertically aligned on one side of the casing). For these cases, the orientation of the perforation with the plane of the hydraulic fracture may be as large as 90°. With 0° phase perforations, near perfect alignment will cause preferential propagation of one wing of the fracture with very limited penetration of the companion wing. Channels are created and cause higher treating pressures because of width restriction (Fig. 5). Fig. 5 also shows a perforation that is approximately 30° out of phase to the fracture plane (minimum stress). The fracturing fluid must partially circumvent the wellbore to reach the fracture. Restrictions may develop, causing an increase in friction pressure and creating the potential for proppant bridging. Even when a perforation is directly in line with the fracture plane, the fracturing fluid must create a path around the wellbore. With 90 or 120° phasing, the fracture plane will generally be less than 30° from two perforations and will result in perforation access to both fracture wings. (Note from Fig. 5 that 180° phasing would not alleviate the misalignment). 2.1.5.3 Perforation Size Fig. 6 illustrates the relation of perforation diameter and proppant concentration. A perforation must be large enough to permit the proppant (at the maximum concentration) to pass through and not bridge in the perforation.



Fig. 6. The relation of perforation diameter and proppant concentration.



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Section 700.1 May 1998 Page 15 of 81



2.2 Closure Test The general steps in a closure-test design are 1.



Determine the fluid type.



2.



Determine the injection rates and number of steps.



3.



Determine the duration of steps.



4.



Determine the flowback rate.



5.



Determine equipment requirements.



2.2.1 Fluid Selection In low-permeability formations, the closure test is usually performed with a Newtonian fluid such as diesel or water containing 2% (wt:wt) potassium chloride. In higher permeability formations (> 10 md) or in formations containing natural fissures, viscosified fracturing fluids may be required to reduce the rate of fluid loss and fracture closure during flowback. The same fluid as the pad fluid of the proposed fracturing treatment would be a good choice in the case of high leakoff. 2.2.2 Injection Rates and Number of Steps When injecting a Newtonian fluid, the range of rates is generally one to ten bbl/min for larger and moderately permeable zones and approximately one-half these values for smaller and very low permeability zones. After a breakdown/diversion treatment has been performed, most zones (k > 0.01 md or h > 30 ft) will require a pump rate greater than 3 bbl/min to exceed fracture extension pressure. The actual range for a particular zone may require trial and error methodology; two or more attempts. Ideally, three values of pressure (end of step) should fall below the extension pressure to define the initial portion for flow into the matrix or a pre-existing fracture, and a similar number of values above the extension pressure to define the portion for extending the fracture. This allows the pressure versus rate plot to be drawn on Cartesian coordinates using the last pressure before a rate change. The intersection of the two straight lines (fracture extension pressure) provides an upper boundary for closure pressure. An additional step-rate/flowback test can be performed to verify correct closure. If there were no pre-existing fracture, the plot of injection pressure versus bottomhole pressure may show an overshoot of the extension pressure for one or two steps because of the larger pressure required for breakdown and initiation of a fracture. 2.2.3 Step Duration For the purpose of defining closure pressure, the duration of the individual rate steps should be equal and can be relatively small. The time required for the pumping equipment to change and maintain a constant rate (one or two minutes) is sufficient. The last step is maintained for a longer time (five to ten minutes). DOWELL CONFIDENTIAL



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All steps, except the last step, should be the same duration. The last step should be long enough to establish some fracture volume, thus allowing the flowback, not leakoff, to bring about closure. Five to ten minutes should be sufficient for the last step. 2.2.4 Flow-Back Rate The step-rate phase is followed by an immediate flowback at a constant rate. Flowback should start immediately after shutdown. The rate must be held constant. Flowback rate is controlled by an adjustable choke or a gate valve and is monitored by a flowmeter. If the flowback rate is within the correct range, the resulting pressure decline will show a characteristic reversal of curvature at the closure pressure. The accelerated pressure decline at the curvature reversal is caused by the flow restriction introduced when the fracture effectively closes. The correct range of flowback rates must be determined by trial and error for any specific field; however, the range is on the order of one-sixth to one-quarter of the fracture extension rate. The effect of flow rates outside the correct range is shown in Fig. 7. A second test may be required if the flowback rate made closure selection impossible. The second test need not include a step-rate phase if clear fractureextension pressure was determined from the first test. Use a different rate the second time. Flowback until bottomhole pressure is within 200 psi of initial reservoir pressure. Do not flow reservoir fluids into the wellbore by flowing back more than was injected. At shut in, the pressure will rebound and stabilize.



Fig. 7. The effects of differing flowback rates. THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY



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Section 700.1 May 1998 Page 17 of 81



2.3 Calibration Test The general steps in a calibration test design are 1.



Determine the fluid type and injection rate.



2.



Determine the fluid volume.



3.



Determine the fluid break time.



4.



Determine if fluid-loss additives are required.



5.



Determine the pressure decline duration.



2.3.1 Fluid Selection The type of fluid and injection rate for the calibration test are the same as the type of fluid and injection rate of the proposed fracture treatment. 2.3.1.1 Foam A foamed fluid may be used for the calibration test. However, the well must be flushed with a linear fluid  a fluid containing no nitrogen, carbon dioxide or crosslinker/activator. Gas in the flush volume will expand due to pressure decline and temperature increase. This will cause fluid displacement into the fracture during closure and will invalidate the decline analysis. If bottomhole pressure is calculated from surface measurements, the hydrostatic pressure will change, adversely affecting the calculations. 2.3.2 Fluid Volume The fluid volume may be determined by using the FGS simulator in the FracCADE software. Use the following methodology.



*



1.



Determine the gross fracture-height and leakoff height.



2.



Using a leakoff coefficient twice the value provided in the Fracturing Materials Manual, calculate a minimum volume to ensure coverage of the zone if the KGD or RAD model is selected (indicated by a lack of barriers). If the PKN model is selected (indicated by significant barriers), calculate a volume sufficient to create a fracture length greater than 1.5 times the fracture height.



3.



If undesired height growth or fissure opening is suspected, treatment design should incorporate methods to avoid them (DIVERTAFRAC* Service, INVERTAFRAC* Service, or fluid-loss additives).



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2.3.3 Fluid Break-Time Fluid break-time is designed for bottomhole static temperature and a long time (compared with expected closure time). Five times the expected pumping time is a good starting place. 2.3.4 Fluid-Loss Additives FLA∗ 100 has particles large enough to be considered a proppant when used in a calibration test. Therefore, FLA100 can cause a screenout and will affect analysis. FLA100 is not recommended for use in a calibration test. However, in naturallyfractured or high-leakoff formations, FLA100 can be used with caution if a sufficient quantity of clean fluid is pumped ahead of it. Fluid-loss additive J84 or fluid-loss additive J418 is not a screenout hazard and may be used in the entire fluid volume for leakoff control. 2.3.5 Duration of Pressure Decline The minimum time that pressure decline should be monitored is 1.25 times the closure time or twice the injection time, whichever is longer. The closure time can be estimated by using the Placement module in the FracCADE software. Estimate the fluid and formation parameters and the volume of fluid to be pumped during the calibration test. A very small proppant stage may be necessary to force the Placement module simulator to run. 2.4 Special Considerations in the DataFRAC Design 2.4.1 The Influence of Wellbore Fluid A large quantity of wellbore fluid injected prior to fracturing fluid entry can result in substantial effects on analysis. If the static wellbore fluid volume is more than 10% of the calibration test fluid volume, one of the following actions should be performed. • Circulate the wellbore fluid out of the tubing with fracturing fluid. •



Bullhead the fracturing fluid to the top perforation at a low rate if circulation is not possible. Allow the pressure to fall below closure pressure before starting the calibration test.



2.4.2 Prepad A prepad is not necessary for the calibration test.



∗



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2.4.3 Closure Pressure less than Hydrostatic Pressure Fluid will flow from the wellbore into the fracture during closure if closure pressure is less than hydrostatic pressure. Calculate the quantity of fluid displaced when closure pressure occurs. If the displaced fluid is more than 10% of the fracture volume at shut-in (volume injected times efficiency), a special wellbore isolation tool should be used in conjunction with a wireline-conveyed bottomhole pressure gauge. Such tools have been used before but may have to be specially constructed. A bottomhole pressure gauge must always be used in these cases. 2.4.4 Post-Job Wireline Surveys Postjob logs should not be run until closure has occurred and pressure monitoring has ceased. Cable movement in the wellbore and fluid drag on the cable can affect the pressure decline data. If postjob logs are to be run, consider using a wireline conveyed bottomhole pressure gauge set below the perforations. 2.5 Terminology 2.5.1 Fracture Extension Pressure The fracture extension pressure is the pressure required to extend an existing fracture. Typically, the fracture extension pressure is 50 to 200 psi greater than the closure pressure because of fluid friction in the fracture and fracture toughness. 2.5.2 Initial Shut-in Pressure The initial shut-in pressure provides an upper bound for the determination of closure pressure. 2.5.3 Closure Pressure An accurate determination of the closure pressure is essential for an analysis of the fracturing pressure because it is the datum for determining the net pressure. The closure pressure is the fluid pressure at which the fracture closes (zero width). This pressure is equal to, and counteracts, the minimum principal stress in the rock that is perpendicular to the fracture plane. The closure pressure reflects a global average of the minimum stress, which is a local quantity and is not constant over the zone of interest. The closure pressure generally is less than the breakdown pressure required to initiate a fracture and always less than the fracture extension pressure. 2.5.4 Rebound Pressure The rebound pressure after shut-in is a lower bound of the closure pressure.



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2.6 Equipment Requirements 2.6.1 Monitoring Equipment An on-site MicroVAX1 computer is not absolutely necessary for performance of the pumping portion of the DataFRAC service. However, a MicroVAX will greatly enhance data manipulation and examination. A MicroVAX computer is necessary if onsite data analysis and treatment design using the FracCADE software is desired. There are two alternatives if a MicroVAX computer is not available. 1.



Perform a hand analysis.



2.



Perform the analysis in the office. This option may force a redesigned treatment to be pumped at some later date.



Two French curves are helpful for determining the reversal in curvature (closure pressure) from the flowback pressure plots. Always carry linear graph paper for any hand plotting needed as well as log-log paper for plotting a Nolte-Smith plot if necessary. 2.6.2 Pumping Equipment Diesel-powered pumpers are recommended for the closure test. Turbine powered pumpers are not recommended for the closure test because rate control is poor, especially at low pressures. Any type of pumpers may be used for the calibration test. 2.6.3 Pressure Measuring Equipment Accurate pressure measurement is critical to the success of the DataFRAC Service. 2.6.3.1 Surface Measurement Methods For the pressure-decline phase of the calibration test, the bottomhole pressure can be calculated from the surface pressure as long as the fluid density is constant and the bottomhole pressure is greater than the hydrostatic pressure. The main problem with using the treating pressure for analysis is that the friction pressure makes the Nolte-Smith plot less accurate and can indicate erroneous trends. In the overall analysis, the Nolte-Smith plot is very valuable if accurate bottomhole pressure and closure pressure are used. A good method for measuring bottomhole pressure is with a “live” annulus or a “dead-string tubing” and a homogeneous fluid. This eliminates friction pressure calculations. With a known hydrostatic pressure, bottomhole pressure can be accurately calculated. The density of the static column of fluid must be known (circulate the well and check the specific gravity of the fluid prior to injection). The fluid must not contain any trapped gas. This method is generally adequate for wells 1



Trademark of Digital Equipment Corporation



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with a bottomhole static temperature less than 250°F (121°C) and a depth less than 10,000 ft. Significant hydrostatic pressure changes may result from a change in fluid density during closure in deep, hot wells. This occurs when the wellbore fluid is warmed by the formation. After pumping, surface pressures can actually increase while the bottomhole pressure decreases (Fig. 8). In a 16,000 ft, 325°F (163°C) well, hydrostatic pressure change can be as much as 250 psi for water (Fig. 9). The effects on oil will be much greater because of the greater thermal expansion of oil. This compromises any results from surface readings because overly optimistic fluidloss and efficiency values will be implied. Therefore, the use of surface readings for deep, hot wells is not acceptable.



Fig. 8. The change in surface pressure during closure in deep, hot wells. THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY



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Fig. 9. Hydrostatic head changes during closure. If closure pressure is less than the hydrostatic pressure of the injected fluid, then pressure analysis is not possible from surface measurement and a wirelineconveyed bottomhole pressure gauge must be used. 2.6.3.2 Bottomhole Pressure Gauge Measurement The best choice for measuring bottomhole pressure is with a bottomhole pressure gauge thereby eliminating friction calculations and hydrostatic considerations. For fluids without proppant, this can safely be done with a wireline-conveyed gauge, in the fluid stream if necessary. To ensure the wireline tension does not exceed a safe level, the increased tension due to fluid drag must be calculated using Eq. 1 before the job begins. T=



π × d ID × d w × Pf 4



(1)



Where: T = tension due to fluid drag (lbf) dID = inside diameter of pipe (in.) dw = diameter of wire (in.) pf = estimated total friction pressure in pipe (psi). Wireline tension must be calculated and confirmed to be safe with the wireline service company prior to rig-up to avoid parting the wire and subsequent job failure. DOWELL CONFIDENTIAL



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A wireline-conveyed bottomhole pressure gauge interfaces through a Remote Data Acquisition (RDA) box. Voltage and frequency inputs for the RDA box are: • 0-20 mA •



4-20 mA



•



0-4000 Hz (12 volts)



Additional information is provided in the PPR System Operator's Manual. Use of the PPR* pumping parameter recorder or other monitoring device is suggested. The wireline-conveyed pressure gauge should be tested prior to job execution. 2.6.4 Treating Equipment Wellhead rig-up requirements must be considered and communicated to the wireline service company. If the injection rate through two-inch treating equipment is greater than 8.5 bbl/min, a frac cross may be necessary. At rates less than 8.5 bbl/min, a lateral may be sufficient. The Dowell Location Safety Standards manual provides the maximum pumping rates through treating equipment. 2.6.5 Flowback Equipment Flowback rate must be monitored accurately for adequate control. Response time on the flowmeter should be 3 sec or less. 2.6.5.1 Magnetic Flowmeters Magnetic flowmeters are used in conjunction with water-base (conductive) fluids. The Dowell Flumag flowmeter is commonly used. Other magnetic flowmeters may be used. Magnetic flowmeter information is provided in the Sensors Verification Guide. 2.6.5.2 Turbine Flowmeters Turbine flowmeters are typically used with oil-base (nonconductive) fluids, but may be used with any fluid type. Turbine flowmeter information is provided in the Sensors Verification Guide. 2.6.5.3 Chokes and Gate Valves An adjustable choke or a gate valve is commonly used to regulate flowback rate.



*



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3 Execution Treatment design for the closure test and the calibration test is provided in Section 2. Location Safety Standard Number 5, 5A, and 5B provides procedures for approved on-location practices. 3.1 Pre-Performance Guidelines Certain guidelines are common for both the closure test and the calibration test. 1.



Equipment is rigged-up in accordance with Location Safety Standard Number 5, 5A, and 5B. Additional details for equipment rig-up and flowback are provided in Fig. 10 (conductive fluids) and Fig. 11 (nonconductive fluids). An adjustable choke or a gate valve is used in place of the choke nipple in the flowline (bleedline).



2.



If a static string is used, ensure the static fluid column is filled with a fluid of known specific gravity with no gas cap. The preferred method is to circulate from the tubing to the annulus at high velocity.



3.



Ensure that suction hoses, discharge hoses, manifolds, pumps, blenders, and discharge piping do not contain proppant.



4.



Backup pressure transducers must be rigged-up and calibrated. Do not provide any more than one display for the same pressure. The transducers are accurate to 1% of full scale. This means a 15,000 psi transducer is accurate to ±150 psi. If the maximum pressure will be low, suggest using a 0 to 5,000 or 0 to 10,000 psi transducer for better accuracy. Do not allow anybody to hammer on transducers during any phase of testing.



5.



The recording period for data acquisition should be 5 to 15 sec. High permeability formations and/or low-volume (short closure time) pump tests require a shorter time interval (5 sec or less). Do not set a PPR to record data from the POD* blender or the storage capacity of the tapes will be exceeded. During the pressure decline, do not allow pausing or constant changing of calculated data.



6.



Determine the expected closure pressure. approximated using Eq. 2.



The closure pressure may be



Approximate closure pressure = Overburden pressure + ( Reservoir Pr essure × 2 3



*



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7. If the wellbore is full of fluid, note the initial bottomhole pressure. Otherwise, note the quantity of fluid required to fill the wellbore (pressure rise). Once the wellbore is full, shut down and record the pisi. Calculate bottomhole pressure using the initial fluid level.



Fig. 10. The DataFRAC Service rig-up when pumping conductive fluids.



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Fig. 11. The DataFRAC Service rig-up when pumping nonconductive fluids.



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3.2 Closure Test The general steps in a closure test are 1.



Rig-up, mix fluid, and perform quality control activities.



2.



Perform the step-rate phase of the closure test.



3.



Perform the flowback phase of the closure test.



4.



Perform a modified step-rate phase if necessary.



5.



Perform a modified flowback phase if necessary.



3.2.1 Step-Rate Phase Step-rate phase guidelines are: 1.



The pump operator should know the pump gear and speed for each of the steps prior to pumping operations. This will facilitate rapid step-rate changes. Getting the injection rate (as well as flowback rate) established quickly must be stressed. Exact rates are not important  constant rates are. Fluid-end ratings and constants are provided in the Treating Equipment Manual. Pump performance curves are provided in the appropriate pumping equipment operators manuals.



2.



Take pressure readings after establishing a new pump rate (prior to increasing the rate again).



3.



Determine if fracture extension is occurring during the last injection stage by plotting rate versus pressure. This will indicate fluid loss to the matrix leakoff or fracture extension (Fig. 2). Fracture extension pressure will be 50 to 200 psi greater than the closure pressure. Remember to plot rate versus bottomhole pressure (not treating pressure). If treating pressure is plotted, the friction pressure will distort the values at higher rates and produce erroneous results.



4.



Increase the pump rate during the last stage if fracture extension is not occurring. If fracture extension is occurring, terminate the stage after the desired length of time. Water hammer effects can be minimized by reducing the pump rate to 10% of the final rate for 10 to 15 sec before shutdown.



5.



Determine the true perforation friction pressure using Eq. 3 and Fig. 12, Fig. 13, Fig. 14, Fig. 15, Fig. 16, or Fig. 17. Using Fig. 18, determine the estimated perforation friction pressure if all perforations were open. If the true perforation friction pressure is greater than twice the estimated perforation friction pressure, wellbore restriction is too great and should be reduced by pumping a diverting treatment or reperforating. Injecting small quantities of proppant near the end of the pad of the proposed fracturing treatment may erode the restriction.



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p pf = pw − ptf − pisi Where: ppf = perforation friction pressure (psi) pw = surface fracturing pressure (psi) ptf = tubular friction pressure (psi) pisi = initial shut-in pressure (psi).



Fig. 12. Friction pressure of water in the tubing and casing.



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Fig. 13. Friction pressure of water in the annulus.



Fig. 14. Friction pressure of brine in the tubing and casing.



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Fig. 15. Friction pressure of brine in the annulus.



Fig. 16. Friction pressure of diesel in the tubing and casing.



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Fig. 17. Friction pressure of diesel in the annulus.



Fig. 18. Flow rate versus differential pressure in perforations. DOWELL CONFIDENTIAL



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3.2.2 Flowback Phase Flowback must be initiated at a constant rate as soon as possible. Remember to isolate the pump(s) from the well. Do not allow bottomhole pressure to fall below 200 psi above the initial bottomhole pressure. Do not flow-back more fluid than was pumped. Note the indicated change in bottomhole pressure during shutdown and calculate the perforation friction pressure. If the perforation friction pressure is more than twice the expected amount, discuss the discrepancy with the client. 3.2.2.1 Flow Control Adjustment of the choke or valve may be accomplished using one of two methods. 1. Pump through the choke or valve prior to performing the step-rate/flowback test to preset the choke or valve. The choke or valve is adjusted to the desired rate when flowback is initiated. 2. Adjust the choke or valve during the last pumping stage of the step-rate test. The pump rate through the choke or valve will be in addition to the pump rate required for the last stage. Flowback rate accuracy is not critical; ± 20% is acceptable. However, a constant flowback rate is critical. Table 1 provides approximate choke settings (using a 15,000 lbf adjustable choke, part number 515077000) for flowback of oil-base fluids. Table 2 provides approximate choke settings for flowback of water-base fluids. Verify the setting by pumping through the choke at the anticipated flowback rate and pressure shut-in pressure. This is a good time to functionally check the flowmeter.



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Table 1. Approximate Choke Settings For Flowback Of Oil-Base Fluids (Sg = 0.7) Pressure (psi) 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000



Flow Rate (bbl/min) 1 14 12 10 10 9 9 8 8 8 8 8 7 7 7 7



3 24 20 18 17 16 15 15 14 14 13 13 13 13 12 12



15 31 26 23 22 21 20 19 18 18 17 17 17 16 16 16



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10 44 37 33 31 29 28 27 26 25 25 24 23 23 23 22



15 53 45 41 38 36 34 33 32 31 30 29 29 28 28 27



20 62 52 47 44 41 39 38 37 36 35 34 33 33 32 31



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Table 2. Approximate Choke Settings for Flowback of Water-Base Fluids (Sg = 1.0) Pressure (psi) 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000



Flow Rate (bbl/min) 1 15 13 11 11 10 10 9 9 9 8 8 8 8 8 8



3 26 22 20 18 17 17 16 16 15 15 14 14 14 14 13



15 34 28 26 24 23 22 21 20 19 19 19 18 18 17 17



10 48 40 36 34 32 31 29 28 28 27 26 26 25 25 24



15 58 49 44 41 39 37 36 35 34 33 32 31 31 30 30



20 68 57 51 48 45 43 42 40 39 38 37 36 36 35 34



The downstream 1 x 2 hamer valve (control valve) in the flowline (bleedline) may be used for flow control if the adjustable choke becomes plugged and can not be cleared. Use the hamer valve for flow control only as a last resort. The choke (or valve) operator must have a rate display for reference. Relaying rates via radio is not acceptable. 3.2.2.2 Flowmeters When using a turbine flowmeter, open the control valve slowly to avoid a fluid surge and subsequent flowmeter damage. Never allow a low-pressure magnetic flowmeter (for example, Fischer-Porter) to be placed upstream of the choke. Flowmeters must have a full pipe of flow to maintain accuracy. A backup flowmeter is recommended. 3.2.3 Closure Test Modifications Modifications to the closure test may be required for the following reasons. • Extension pressure was not attained. •



An overshoot of fracture extension pressure took place.



•



Flowback rate was inaccurate.



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Section 700.1 May 1998 Page 35 of 81



3.3 Calibration Test The general steps in a calibration test are 1.



Rig-up, mix fluid, and perform quality control activities.



2.



Perform the injection phase of the calibration test.



3.



Perform the pressure-decline phase of the calibration test.



3.3.1 Injection Phase The type of fluid and injection rate for the calibration test are the same as the type of fluid and injection rate of the proposed fracture treatment. Injection phase guidelines are 1.



If the flush fluid volume is more than 10% of the calibration fluid volume, the treatment fluid should be circulated to the top perforation. If circulation is not possible, pump the tubing volume (or annular volume, whichever is applicable) at low rate. Stop pumping and let the pressure fall below closure before resuming pumping. Fluid warming will change the fluid characteristics. Do not wait any longer than necessary if the well has a high bottomhole static temperature.



2.



When using crosslinked fluids, accurate crosslinker/activator additive rate is especially critical for correct DataFRAC analysis. A linear fluid, as opposed to a crosslinked fluid, will cause a different pressure response and have different fluid-loss characteristics. A back-up additive pump is recommended.



3.



Use the closure pressure determined from the closure test in calculation of net pressure for the Nolte-Smith plot. Reset pump time to zero when fluid enters the perforations and start the plot.



4.



Calculate fluid friction pressure using bottomhole pressure or obtain the shut-in pressure during the calibration test. Initial shut-in pressure obtained after pumping the flush fluid yields friction pressure for the flush fluid, not the calibration fluid.



5.



Stop pumping when flush is complete. Reduce water hammer effects by reducing the pump rate to 10% of the final rate for 10 to 15 sec before shutdown.



6.



Record the shut-in pressure when the pump rate falls to less than 2% of the treatment pump rate.



7.



Isolate the pumping equipment when all pumping has stopped.



8.



Calibration tests using foamed fluids must be flushed with a linear fluid not containing carbon dioxide, nitrogen, or crosslinker/activator.



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3.3.2 Pressure-Decline Phase Pressure-decline phase guidelines are 1.



Monitor pressure decline for 1.25 times the closure time or for twice the injection time, whichever is longer. Recording closure is very important.



2.



Do not allow anybody to hammer on the line or disturb the transducers during monitoring activities.



3.



Do not run postcalibration-test wireline surveys during monitoring activities.



4.



If the annulus is isolated, do not reduce or increase pressure during monitoring activities. Expansion or contraction will affect the tubing pressure and the final analysis if surface pressure is used.



3.3.3 Contingency Plans 1.



If an operational problem occurs with less than 30% of the fluid volume pumped, stop pumping and correct the problem. Resume pumping the remaining fluid at the design rate. Do not continue pumping at a reduced rate. Do not be concerned about a fluid leak unless the leak causes safety concerns or is tremendous, (gallons/minute). The volume loss compared to the leakoff in the fracture is small and will not affect the pressure decline.



2.



If an operational problem occurs with approximately 50% of the fluid volume pumped and the problem can be corrected quickly, stop pumping and note the loss of net pressure. If more than 20% of the net pressure is lost, consider a) starting over b) monitoring the pressure decline and pumping a second calibration test with the remaining fluid. If less than 20% of the net pressure is lost, resume pumping and analyze using the total volume pumped and the final injection rate. The pump time will be filled in on the DataFRAC form.



3. If an operational problem occurs with more than 70% of the fluid volume pumped, stop pumping and monitor the pressure decline. Be sure to use the actual volume of fluid injected into the formation in the analysis. At least 50% of the total volume should be pumped at the designed rate.



4 Evaluation The DataFRAC analysis consists of three essential parts. 1.



closure test for closure pressure



2.



calibration injection for fracture geometry



3.



calibration decline for fluid-loss behavior



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For correct analysis, the actual bottomhole pressure (BHP) must be used (See Ref. 2: Chapter 7.6.2). Combining the analysis of the closure test, pressure during pumping (as predicted by a fracture simulator) and pressure decline during closure provide a consistent interpretation and the enhancement of the three parts. Consistent values of the fracturing parameters for all the three analysis provide a sound basis for proper DataFRAC evaluation and subsequent treatment design. 4.1 Closure Test Analysis The closure pressure is the fluid pressure for which the fracture effectively closes without proppant. The closure pressure is distinguished from the minimum stress. The stress is a local parameter which can vary over the pay zone, whereas the closure pressure is a global parameter reflecting the gross behavior of the pay zone. The field procedures for the closure pressure test require the creation of a fracture in the complete zone as opposed to a “micro” fracture for the stress test. The methods used for determining the closure pressure include the step rate and flowback test. The step rate is analyzed using a BHP versus rate plot and the flowback is analyzed using a BHP versus time plot. 4.1.1 Step Rate  The BHP-Versus-Rate Plot The BHP-versus-rate plot (Fig. 2 and Fig. 3) should show two different slopes indicating matrix leakoff at low pressures/rates, and fracture response at higher pressures/rates. The extension pressure provides an upper bound for the closure pressure and defines the required range of pump rates for extending a fracture in the zone. 4.1.2 Flowback  The BHP-Versus-Time Plot The inflection point from concave up to concave down on the BHP-versus-time plot (Fig. 19) of the flowback response, is the point of increased pressure drop through the entrance of the fracture. The lowest point of the pressure derivative curve will be the inflection point. Several publications prior to 1993, indicated closure occurred at the inflection point. Subsequent analysis, with a comprehensive fracture simulator, indicated closure pressure occurs at a lower pressure and near the intersection of the tangents shown in Fig. 19.



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Fig. 19. Flowback test (after Nolte, 1982/1994). 4.1.3 Confirmation of Closure Pressure The confirmation of closure pressure can be done using the square-root of time plot or G-plot during the shut-in of the calibration treatment. The closure pressure is inferred as change of the slope on either of these plots (Fig. 20). This method normally does not provide a definitive indication of the closure pressure because of the existence of multiple slope changes. The fracture closure generally causes one of the slope changes in the BHP versus: t plot. A change in slope of the “G” plot also is a typical indication of closure pressure.



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Fig. 20. Effect of closure on BHP versus square root of t and G- plots.



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4.1.4 Rebound Pressure After the pressure drops below the estimated closure point during flowback, the well is shut-in and the rebound pressure is monitored. The rebound pressure provides a lower bound of the closure pressure and the inflection point provides an upper bound of the closure pressure (Fig. 21).



Fig. 21. Rebound pressure; lower bound of closure pressure. 4.2 Calibration Injection for Fracture Geometry The Nolte-Smith plot (log-log plot of the net pressure versus pumping time) provides an important diagnostic tool for determining how the fracture is propagating and the fracture geometry during pumping. The analysis enables the simulation and calibration of the pressure with a numerical fracture simulator and permits reconciliation of the ideal assumptions and actual field conditions. The magnitude of the net pressure from the fracture simulator permits a verification of fracture parameters such as modulus, height, toughness or barrier stress difference.



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4.2.1 Elastic Fracture Compliance For fracturing applications, the linear elastic assumption of Sneddon's classical solution is applied. From the solution, the average fracture width can be expressed in terms of the closure pressure (pc) fracture compliance (cf) and net wellbore pressure (∆pf) as: w = c f ∆p f = c f ( p f − pc ), Where: cf =



πβd 2 E'



Fig. 22 indicates that the behavior of a pressurized crack is analogous to a preloaded spring. pc 1 E' ∝ cf d



= “spring pre-loaded” = “spring constant” ___



E



∆p f Pw − Pc = rock modulus



d



= “characteristic” dimension of frac geometry



β



=



(see Section 4.3.8.4)



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Fig. 22. Analogy of a pressurized crack to a pre-loaded spring.



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The average crack width can be expressed by Sneddon's relationship in terms of “d”, πβd ( p f − pc ) 2 E' This relationship is used to model a fracture as follows: xf • PKN: → ∞ d = hf hf w=



•



KGD:



•



Radial:



hf → ∞ d = 2x f xf 2x f 32 →1 d= R ≈ R and x f = R. hf 3π 2



The KGD model is more appropriate when the fracture length is smaller than the height, while the PKN model is more appropriate when the fracture length is much larger than the height. The radial model is most appropriate when 2xf is about equal to the height. 4.2.2 Pressure During Pumping 4.2.2.1 Fluid Flow and Pressure in Fracture The pressure gradient in the fracture can be expressed as; n′



dp K'  q  ∝ 2n' +1  i  . dx w  hf  This expression relates the gradient down the fracture length to the fluid velocity or flow rate. Introducing the fracture compliance (w = cf∆ pf), integrating along the fracture length and assuming ∆pf = 0 at the tip, results in; 1



1.



 K '  q  n'  ( 2n' + 2) ∆p f ∝  2n' + 1  i  x f  c f   hf   



1 n'  2n



  qi  w = c f ∆p f ∝  c f K ' x f     hf    



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These proportionalities indicate the effect on pressure and width from variations of fluid rheology, injection rate, fracture geometry and models (in terms of fracture compliance). Substituting the appropriate compliance relationship for the three basic models gives; •



1



PKN:



 x f  ( 2n' + 2) ∆p f ∝ A 3n' +1  ,  h f  1



•



  ( 2n' + 2) 1 ∆p f ∝ A n 2n'  ,  h f x f 



KGD:



1



•



 1  ( 2n' +2) ∆p f ∝ A 3n'  . R 



Radial:



A = (E



Where:



2n' +1



1 n ′ ( 2n' + 2) K ' qi ) ,



which is the same for all the three models. The relationships also indicate that with increasing penetration, the net pressure increases for PKN model and decreases for the KGD and radial models. For constant injection rate, the fracture growth can be expressed in terms of time and bounded by two extreme cases for fracture efficiency, η: • Upper bound: No fluid loss (that is, Vf = Vi = qit). V f = w A f ∝ t ; η → 1 •



Lower bound: Almost total fluid loss (that is, VL → Vi = qit and Vf → 0). A f ∝ t 1/ 2 ;



η→0



A f = fracture face area. The fracture penetration increases with time and depends on the fluid loss during injection. By combining the bounds for time dependence of penetration, the relationship for net pressure and width, the net pressure yields; ∆p f ∝ t 1/ 4( n' +1) ( η → 0) • PKN: ∆p f ∝ t 1/( 2n+ 3) ( η → 1)



•



•



KGD:



Radial:



∆p f ∝ t − n'/2 ∆p f ∝ t − n'/(



( n' +1) n' +2)



∆p f ∝ t −3n'/8 ( n' +1)) ∆p f ∝ t − n'/( n' +2)



( η → 0) ( η → 1) ( η → 0) (η → 0)



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The previous expressions for pressure assume the fluid viscosity dominates the pressure distribution and ignores the fracture toughness of the formation. This assumption is generally valid for fractures with dimension in excess of 50 ft using high-viscosity fluids. For the case of small-scale fractures created with low viscosity fluids, fracture toughness can dominate and result in different exponents for time. The expressions for the net pressure are all exponential expressions. As a result, a log-log plot of net pressure versus time should yield a straight line with slope equals to the respective exponents: positive for PKN and negative for KGD and radial models. The log-log plot of net pressure versus time as introduced by Nolte and Smith, forms a basis for the interpretation of pressure data during fracturing. 4.2.2.2 Nolte-Smith Plot and Evolution of Pressure During Pumping Fig. 23 shows the evolution of the fracture geometry and the Nolte-Smith plot for an ideal case with bounding formations of higher stress. During the initial phase of propagation (stage 1), the fracture area increases in the radial mode (point source) or as expanding ellipses (line source). The line source can be approximated by KGD model. For this initial phase, the log-log slope is negative and between -1/8 and 1/4. This phase continues until the fracture is affected by barriers, which may occur after a very short time.



Fig. 23. Evolution of fracture geometry and pressure during pumping. The fracture will then propagate in PKN mode after the radial model encounters barriers above and below (stage 2) which results in increasing pressure and the loglog slope is between 1/4 and 1/8. Without proppant, the net pressure is limited to a DOWELL CONFIDENTIAL



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value slightly below the stress difference (∆σ) of the barrier being penetrated. At this time, the height begins to increase significantly and the pressure would be approximately constant (stage 3). Nearly constant pressure indicates the pressure capacity for the formation, which is determined by in-situ stress difference. When the net pressure reaches this capacity, fracture extension becomes relatively inefficient, as discussed in the following sections. 4.2.3 Deviations from Ideal Geometry 4.2.3.1 Height Growth Height growth into stress barriers is a common deviation from the ideal PKN model. Fig. 24 illustrates the pressure and vertical cross section of the width profile. Stage “a” is the PKN propagation stage. The positive log-log slope will continue until the net pressure approaches the stress difference of the barrier. At this stage (stage “b”), the height will increase and the pressure would be approximately constant. During stage “c”, the barrier is crossed and the fracture enters a lower stress zone resulting in an accelerated rate of growth at decreasing pressure and width in the primary zone. The width profile indicates that a “pinch point” occurs in the barrier after stage “b”. The pinch point has essentially no width during the transition from stage “b” to stage “c”. The pinch point can cause proppant to bridge as fluid is permitted to pass through. The resulting excessive dehydration of the slurry coupled with the decreasing width can result in a rapid screenout even at low proppant concentration.



Fig. 24. Pressure and width for height growth through barriers (after Nolte, 1989).



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The slurry dehydration, decreasing width, and height growth can be reduced by the following methods: 1.



Place an impermeable mixture of proppant between the pad and the proppant stages to form an impermeable bridge at the pinch point.



2.



Pumping a pre-treatment DIVERTAFRAC).



with



a



diverting



agent



(INVERTAFRAC



or



4.2.3.2 Fissures Another possible cause for a period of constant pressure is the opening and inflating of natural fissures. Pressure-dependent leakoff due to fluid loss into fissures is thought to contribute to screenouts in low permeability formations where limited fluid loss would otherwise be anticipated. Two fissure models have been reported.



1.



Slight permeability enhancement The permeability enhancement is not significant until the effective stress becomes negative and the fissure aperture opens. At this time, fluid loss becomes significant and regulates the pressure to a constant value.



2.



Highly stress-sensitive permeability and fluid loss The permeability and fluid-loss enhancement are significant throughout the treatment, with the effect accelerating as the pressure increases. If the treatment continues, the negative effective stress condition can occur with constant pressure.



Fig. 25. Pressure and width for opening natural fissures (after Nolte, 1989).



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Fig. 25 illustrates the pressure response and the horizontal cross section of the width profile. The secondary fracturing occurs in natural fissures or cracks which are crossed by the primary fracture. These feature normally have relatively higher permeability than the matrix and the fluid leakoff is high. The fissures will open when the fluid pressure exceeds the formation stress acting across them. σ − σ1 ∆p f > 2 ≈ 1.5 ∆σ H 1 − 2ν ∆σH = σ2 - σ1 = horizontal stress difference. This implies that effective fracturing will require a significant stress difference between the principal horizontal stress to avoid opening of natural fissures. When this magnitude of pressure is reached, the fissures open and act to regulate the constant pressure at this critical magnitude. A significant portion of the injected fluid can be lost because of a large number of fissures that can open at this critical pressure. The accelerated fluid loss can lead to excessive slurry dehydration and a screenout (stage “c” of Fig. 25). The accelerated fluid loss can be reduced using the following methods. 1.



Before the fissure aperture opens, use very fine particles (for example, 300-mesh particles) in the pad.



2.



After the fissures open, and maintain constant pressure, use 100-mesh particles between the pad and proppant stages (Note: 100-mesh particles can screenout the treatment when they reach the tip).



4.2.3.3 T-Shape Fracture



Fig. 26. Pressure and width for T-shape fracture (after Nolte, 1989). DOWELL CONFIDENTIAL



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When the fracturing pressure is greater than overburden stress, a fracture can propagate in both the horizontal and vertical planes. This geometry is called a T-shape fracture and the pressure response and a vertical cross section of the width profile are illustrated in Fig. 26. The figure indicates stage “c” has a near constant pressure response. The horizontal component growth requires pressures greater than the overburden pressure and occurs at; ∆p f ≥ OB − pc Where: OB = vertical overburden stress pc = closure pressure. The width of the horizontal fracture component will be narrow and have twin pinch points at the juncture with the vertical component. The limited width of the horizontal component can restrict proppant entry, excessively dehydrate the slurry in the vertical component, and lead to premature screenout. The T-shape fracture is the easiest to diagnose: Bottomhole injection pressure approximately constant at a value slightly above the overburden pressure (that is, about one psi/ft of true vertical depth). 4.2.4 Pressure Capacity Summarizing the prior sections (using Fig. 27) a period of constant pressure for a vertical fracture can occur because  • The pressure approaches the stress of a barrier and causes significant height growth; ∆p f ≤ ∆σ ν •



•



∆σv = barrier stress difference. The pressure exceeds the stress acting on natural fissures and the fissures open; ∆σ H ∆p f ≈ . 1 − 2ν The pressure exceeds the overburden pressure, and the initiation of T-shape fracture begins;



∆p f ≥ OB − pc



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Fig. 27. Definition of pressure capacity from in-situ stresses. For these cases, the limiting pressure is called the formation pressure capacity. The formation acts as a pressure vessel with a pressure capacity defined by stress differences. Exceeding the pressure capacity leads to inefficient extension due to height growth, the formation of T-shape fracture or fissures opening. 4.2.5 Near-Wellbore Restriction High near-wellbore pressure losses sometimes experienced during the hydraulic fracturing treatment should be considered in fracturing pressure analysis, that is, subtracted for determining net pressure. In addition to inadequate perforating, a potential cause of high near-wellbore pressure losses is that the well and the fracture plane are not aligned, that is, on deviated wells or wells close to faults (deviated principal stress). For these cases, the fracture initially aligns with the wellbore, and then turns to align normal to the far-field minimum stress. The fracture entrance experiences a normal stress greater than the minimum stress, leading to a fracture width restriction and increased pressure losses within the entrance. The stress state within the entrance is illustrated by Fig. 28 and the Mohr circle in Fig. 29. AB = fracture plane σ1 = minimum principal stress σy = stress parallel to the wellbore σx = stress normal to the wellbore. DOWELL CONFIDENTIAL



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Fig. 28. Stress state within the entrance of deviated well or stress. For the deviated stress case, σy and σx are equal to overburden and horizontal stress, respectively. The principal (that is, minimum and maximum) stresses are not horizontal or vertical and the fracture is inclined. For the deviated well case, the principal stresses are assumed horizontal and vertical, σy and σx are parallel and normal to the inclined wellbore. σx can be estimated as the sum of the minimum stress (that is, closure pressure) and the apparent near-wellbore friction, pwf; that is, DOWELL CONFIDENTIAL



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σx = σ1 + pwf with σ1 estimated from a closure pressure test and pwf from the BHP change during a shut-in.



Fig. 29. Mohr circle of deviated well or stress. Using the Mohr's circle in Fig. 29, information about the state of stress and relative fracture orientation can be obtained from known information (for example, θ for deviated well, or σy = OB for vertical well). Radius of Mohr circle,



R=



σx + σy − σ1 2



Therefore; cos 2θ =



R − pwf , R



Where: θ = angle between wellbore axis and fracture plane pwf = near-wellbore friction pressure. Significant entrance friction can be diagnosed by a large difference in the bottomhole injection pressure during fracturing and the initial shut-in pressure (ISIP). The entrance friction responds the same as perforation friction and tends to decrease when proppant is added. For pre-fracture tests, a significant entrance restriction can be indicated by a large difference (for example, greater than 200 psi) between the extension pressure (Fig. 2 and Fig. 3) and closure pressure (Fig. 20 and Fig. 21).



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4.2.6 Fracturing Pressure Interpretation Summary



Fig. 30. Nolte-Smith plot of fracturing pressure. Small Positive Slope The fracture is propagating under contained height and free lateral extension in a manner similar to PKN model. The approximate log-log slope is 1/8 to 1/4.



Zero Slope Reduced penetration rate potentially caused by: height growth, fissures opening or the formation of T- shape fracture. The constant pressure during this period is called formation pressure capacity which is determined by the in-situ stresses; and hence likely to be the same for offset wells.



Positive Slope Flow restriction causing fracture width to be increased with limited extension, potential proppant bridging and screenout. 1− η ∆t D • Tip screenout condition, the log-log slope ≈ 1 + 0.64 η where η is the efficiency at screenout and ∆tD is the time after screenout divided by the screenout time. •



Log-log slope > 1 indicates restriction in the fracture.



•



Log-log slope >>1 (very high slope) indicates restriction near or at the wellbore resulting from a near-wellbore restriction (Section 4.2.5) or exceeding the pressure capacity (Section 4.2.4). DOWELL CONFIDENTIAL



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Negative Slope Unrestricted height growth through a lower stress formation. It also indicates growth of a radial fracture with the fracture propagating in a manner similar to the KGD or radial model. 4.2.6.1 Example of Radial Fracture Fig. 31 shows the interpretive log-log plot of a radially propagating fracture from a calibration treatment of a massive chalk section in the North Sea. The plot shows the expected behavior of a radial fracture with a log-log slope equal to about – 1/8. The period of lower pressure at about 10 min resulted from a shut-in. The small pressure change of about 50 psi indicates there was no significant entrance restrictions.



Fig. 31. Net pressure with radial fracture (after Smith et al. 1987). 4.2.6.2 Simulation of Pressure During Pumping and Decline The numerical simulation of the pressure response is an important tool in the calibration injection for fracture geometry and calibration decline, for cases in which the idealized 2D geometry models are inadequate. These nonideal cases may include height growth, stress sensitive fissures, and fracture penetration and recession during the decline. The log-log plot of the fracturing pressure is generally a qualitative and diagnostic tool. Quantitative interpretation can be obtained by comparing the predictions from a DOWELL CONFIDENTIAL



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numerical fracture simulator and the actual treatment. The net pressure is primarily governed by the rock mechanical properties and is relatively insensitive to rate and viscosity. Numerical simulation is used to calibrate or confirm values for the parameters that govern the pressure response, that is, fracture compliance, rock stress difference and fluid-loss coefficient. The calibrated parameters can then be used to make design changes in subsequent treatments. Even though there is not a unique set of fracturing parameters that match a pressure response, a calibrated set provides a rational basis for more effective treatment design.



Fig. 32. Measured and simulated net pressure: opening natural fissures (after Nolte, 1982). Fig. 32 shows an example of the reported application of fracturing pressure simulation during injection and decline. The pressure plot shows a near-constant pressure period indicating that the formation capacity has been reached. The pressure capacity value of 1700 psi, because of the opening of natural fissures, lasted for about 100 minutes prior to shut-in. The pressure capacity is governed by the rock stress and should be expected to be similar throughout the field, provided there are no significant lithological or tectonic changes. Consequently, once the pressure capacity is determined and the pressure calibrated by the simulator, rational design changes can be made for more effective treatment for the remainder of the wells in the field, that is, design using a pressure calibrated simulator to stay below the pressure capacity for more efficient penetration. In addition, the pressure simulation during decline may provide consistent interpretation and result in enhancement of both injection and closure analysis; however, an appropriate numerical fracture simulator is required to correctly apply these concepts. Ideally the simulator should include the effects of spurt loss, pressure-dependent fluid loss (with and without sensitive fissures), fluid temperature and compressibility, poroelastic stress changes, height growth, and fracture penetration and recession during closure. The Placement II fracture simulator in the FracCADE software addresses most of these effects.



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4.3 Calibration Decline for Fluid-Loss Behavior An analysis and use of a specialized plot for the pressure decline during shut-in, pioneered by Nolte, provides relationships for width, penetration, fluid efficiency and fluid-loss coefficient in terms of rate of pressure decline and closure time after injection. The leakoff coefficient can be quantified from the rate of pressure decline, an important parameter in fracture treatment design. Fig. 33 shows the pressure decline period between the end of pumping and closure.



Fig. 33. Example of fracturing-related pressures (after Nolte, 1982). 4.3.1 Review of Decline Analysis The bases for the information within the following sections comes from SPE 25845, “A Systematic Method for Applying Fracturing Pressure Decline” by Nolte et al and should be consulted if required for more detail. The assumptions of the basic decline analysis are • constant fluid density •



constant fracture area



•



constant β (dimensionless fluid pressure distribution)



•



constant cf (fracture compliance)



•



constant closure pressure



•



constant fluid-loss area and coefficient



•



Spurt loss is negligible after shut-in



•



The fluid loss follows the Carter assumptions of:



•



Fracture area during injection evolves with the relation A ∝ t α ( 0. 5 < α < 1).



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The last condition is met if injection conditions are approximately constant and excessive height growth does not occur. The fracture area evolves in time as (see Fig. 34) The area exponent (α) can be found using two bounding cases: a



A t =  . Af  ti  •



Lower bound η → 0, α0 = 0.5



•



Upper bound η → 1, α1 = (2n + 2)/(2n + 3) PKN α1 = (n + 1)/(n + 2) KGD α1 = (4n + 4)/(3n + 6) Radial



with n = the power-law fluid exponent.



Fig. 34. Schematic for fracture area and time. The appropriate value of α for use in an application can be found by interpolating using the actual value of efficiency; α = 0.5 + η (α1 - 0.5). The interpolated values of α over the full range of n are provided in Table 3, from which a typical value is α ≈ 0.6 for 0.4 < n < 0.6 and 0.2 < η < 0.6.



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Table 3. Interpolated Values of α Over the Full Range of n n′



0.4



0.6



0.8



Efficiency PKN KGN Radial PKN KGD Radial PKN



1.0



KGD Radial PKN



KGD



Radial



0



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.50



0.2



0.55



0.52



0.55



0.55



0.52



0.56



0.56



0.53



0.57



0.56



0.53



0.58



0.4



0.60



0.53



0.61



0.61



0.55



0.63



0.61



0.56



0.64



0.62



0.57



0.66



0.6



0.64



0.55



0.67



0.66



0.57



0.69



0.67



0.59



0.71



0.68



0.60



0.73



0.8



0.69



0.57



0.72



0.71



0.59



0.76



0.73



0.61



0.79



0.74



0.63



0.81



1.0



0.74



0.58



0.78



0.76



0.62



0.82



0.78



0.64



0.86



0.80



0.67



0.89



4.3.2 Volume Function g For the decline assumptions, the volume lost during pumping and shut-in can be derived analytically and expressed in terms of volume function g(∆tD). The volume lost during pumping; VLP = 2κgo C L rp A f t p . The volume lost during shut-in;



[



]



VLS = 2C L rp A f t p g( ∆t D ) − go , Where: g( ∆t D ) = 4 / 3[(1 + ∆t D ) 3 / 2 − ∆t D3 / 2 ] with go = g(o ) =



4 3



for α = 1,



1/ 2 g( ∆t D ) = (1 + ∆t D )sin − 1 (1 + ∆t D ) − 1/ 2 + ∆t D π 1 with go = for α = , 2 2 Sp κ = spurt correction = 1 + . go C L t p



g(∆tD) as function of ∆tD is shown in Fig. 35. It is important to note that the difference between the upper and the lower bound decreases significantly during the shut-in period (that is, the precise value of α is not critical).



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Fig. 35. Dimensionless volume function for fracture closure (after Nolte, 1986). 4.3.3 Fluid Efficiency The fluid efficiency is the ratio of fracture volume to the total volume injected. For ideal conditions and no proppant, the efficiency can be expressed in terms of the dimensionless closure time (refer to Section 4.3.4 for efficiency in terms of G function); V f ( ∆t = 0) VLS ( ∆t = tc ) = Vi VLP + VLS g( ∆tcD ) − go η= . g( ∆tcD ) + (κ − 1)go η=



For the case of no spurt, κ = 1 and the efficiency; η=



g( ∆tcD) − go g( ∆tcD)



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Fig. 36. Efficiency from closure time for no proppant, no spurt loss during pumping and other ideal assumptions given in Section 4.3.1 (after Nolte, 1986). Fig. 36 shows the relationship of η and the dimensionless closure time for the nonpropped case. The relationship is constructed in terms of upper and lower bound (α = 1 and α = 0.5). For determining the effect of proppant on efficiency, the proppant volume will be expressed as the bulk proppant volume fraction; v prop =



v prop Vi



Where: Vprop = proppant bulk volume Vi = total slurry volume injected. The expression for efficiency can be shown as follows (See Ref. 2); η=



(V f − Vprop )(1 − v prop ) (1 − v prop ) Vf = = η' Vi v prop  v prop    (Vi − Vprop ) 1 −  1 −  η  η   



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Vf is the fracture volume at the end of pumping. Denoting the apparent efficiency η’ based on closure time assuming no proppant (that is, Fig. 36) and rearrange the previous equation, the efficiency of a propped fracture can be determined from η’; η = v prop (1 − η' ) + η' 4.3.4 Decline Function G The pressure decline analysis utilizes a plot of net pressure versus the dimensionless decline function G; G ( ∆t D ) =



4 [ g( ∆t D ) − go ]. π



A combination of fracture compliance, material balance and the relationship between the generated fracture area and time permit the development of the pressure decline analysis. If the ideal assumptions of the basic decline analysis hold, the basic pressure decline relation gives; cf



π dpw dG( ∆t D ) =− t p C L rp . dt dt 2



At shut-in, the pressure is pws with ∆tD = 0 giving a relationship between pw versus G(∆tD); πC L rp t p Pw = pws − G( ∆t D ) . 2c f This provides a straight-line interpretation with negative slope, mG = p*, of the plot of pw versus G(∆tD) as shown in Fig. 37. Where p* is defined as; p* = =



πC L rp t p



2c f This relationship is used to infer a leakoff coefficient (CL). It should be noted that if the ideal assumptions are not valid, the straight line can not be identified and mG ≠p*. Fig. 37 shows the conceptual response of the ideal pressure decline.



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Fig. 37. Conceptual response of pressure decline versus Nolte time-function (after Castillo, 1987). The G-plot is analogous to the use of a Horner plot for pressure buildup or falloff to characterize reservoir flow parameters. In addition to the leakoff parameters, it provides the diagnostic for the deviations from ideal behavior, as discussed in Section 4.3.5. From the efficiency expression in Section 4.3.3, definition of G and go ≈π;/2, the fluid efficiency for ideal behavior can be expressed in terms of “G” function; η' =



Gc 2κ + Gc



where Gc = G(∆tcD) = G at closure and κ = 1 for no spurt. The values of decline function “G” are provided in Table 4 in terms of α and ∆tD. This table is used to calculate G(∆tD) if the DataFRAC software is not available. α is typically between 0.5 and 0.7. For most applications, α ≈ 0.6 can be assumed with sufficient accuracy for fracture closure analysis.



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Table 4. Values of Decline Function "G" α



0.5



0.6



0.7



1.0



∆tp



g



η



G



g



η



G



g



η



G



g



η



G



0.00 0.02 0.04 0.06 0.08 0.10 0.12



1.57 1.60 1.63 1.66 1.68 1.71 1.73



.000 .018 .035 .051 .066 .080 .093



0.000 0.038 0.073 0.108 0.141 0.174 0.206



.000 .020 .038 .055 .070 .085 .099



0.000 0.039 0.076 0.112 0.147 0.180 0.213



1.48 1.51 1.54 1.57 1.60 1.62 1.65



.000 .021 .041 .058 .075 .091 .105



0.000 0.041 0.080 0.117 0.152 0.187 0.221



1.33 1.37 1.40 1.44 1.47 1.50 1.52



.000 .027 .050 .071 .091 .109 .126



0.000 0.046 0.089 0.130 0.169 0.207 0.244



0.14 0.16 0.18 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.80 2.00 2.20 2.40 2.60 2.80 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 7.00 7.50



1.76 1.78 1.80 1.83 1.88 1.94 1.99 2.04 2.09 2.14 2.19 2.23 2.32 2.41 2.49 2.57 2.65 2.72 2.80 2.87 2.94 3.00 3.14 3.26 3.38 3.50 3.61 3.72 3.83 4.08 4.32 4.54 4.76 4.97 5.16 5.35 5.54 5.71



.106 .118 .129 .140 .166 .190 .211 .231 .249 .266 .282 .297 .324 .348 .369 .389 .407 .423 .438 .452 .465 .477 .499 .518 .535 .551 .565 .578 .589 .615 .636 .654 .670 .684 .696 .707 .716 .725



0.237 0.267 0.297 0.327 0.399 0.468 0.535 0.600 0.663 0.725 0.785 0.844 0.957 1.066 1.172 1.273 1.372 1.467 1.560 1.651 1.739 1.825 1.992 2.152 2.305 2.454 2.598 2.737 2.872 3.195 3.498 3.786 4.060 4.322 4.573 4.816 5.050 5.276



1.52 1.55 1.58 1.61 1.64 1.66 14.6 9 1.72 1.74 1.76 1.79 1.85 1.90 1.96 2.01 2.06 2.11 2.16 2.20 2.29 2.38 2.46 2.54 2.62 2.70 2.77 2.84 2.91 2.98 3.11 3.24 3.36 3.48 3.59 3.70 3.81 4.06 4.30 4.53 4.75 4.95 5.15 5.34 5.52 5.70



.112 .125 .137 .148 .175 .199 .221 .241 .260 .277 .293 .308 .336 .360 .382 .401 .419 .435 .450 .464 .477 .489 .511 .530 .547 .562 .576 .589 .600 .625 .646 .664 .679 .692 .704 .715 .724 .733



0.245 0.277 0.308 0.338 0.411 0.482 0.551 0.617 0.681 0.744 0.805 0.865 0.980 1.091 1.197 1.300 1.399 1.496 1.590 1.681 1.770 1.857 2.025 2.186 2.340 2.490 2.634 2.774 2.910 3.234 3.539 3.827 4.102 4.635 4.617 4.860 5.095 5.322



1.68 1.70 1.73 1.75 1.81 1.87 1.92 1.97 2.03 2.08 2.12 2.17 2.26 2.35 2.44 2.52 2.60 2.67 2.75 2.82 2.89 2.96 3.09 3.22 3.34 3.46 3.57 3.68 3.79 4.05 4.29 4.51 4.73 4.94 5.14 5.33 5.51 5.69



.119 .132 .145 .157 .184 .209 .232 .252 .271 .289 .305 .320 .348 .372 .394 .414 .432 .448 .463 .477 .489 .501 .523 .542 .558 .573 .587 .599 .611 .635 .656 .673 .688 .701 .713 .723 .732 .741



0.254 0.286 0.318 0.349 0.424 0.497 0.566 0.634 0.700 0.763 0.825 0.886 1.003 1.115 1.223 1.326 1.427 1.525 1.619 1.711 1.801 1.889 2.058 2.220 2.376 2.526 2.671 2.812 2.948 3.274 3.579 5.869 4.145 4.408 4.661 4.905 5.140 5.367



1.55 1.58 1.61 1.63 1.70 1.76 1.82 1.87 1.93 1.98 2.03 2.08 2.17 2.27 2.35 2.44 2.52 2.60 2.67 2.75 2.82 2.89 3.03 3.16 3.28 3.40 3.52 3.63 3.74 4.00 4.24 4.47 4.69 4.90 5.10 5.29 5.48 5.66



.141 .156 .170 .184 .214 .241 .266 .288 .308 .326 .343 .359 .387 .412 .433 .453 .471 .487 .501 .515 .527 .539 .560 .578 .594 .608 .621 .633 .643 .666 .686 .702 .716 .728 .738 .748 .757 .764



0.280 0.315 0.349 0.382 0.463 0.540 0.614 0.685 0.754 0.821 0.886 0.949 1.071 1.187 1.299 1.406 1.510 1.610 1.708 1.802 1.894 1.984 2.157 2.322 2.481 2.633 2.781 2.924 3.062 3.392 3.701 3.994 4.272 4.538 4.793 5.038 5.275 5.504



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4.3.5 Non-Ideal Behavior The assumptions of the basic decline analysis are seldom met in practice. Several deviations from these ideal assumptions that have to be considered are • change in fracture penetration after shut-in •



height growth



•



pressure-dependent fluid loss



•



spurt



•



closure pressure change



•



compressible fluids.



4.3.5.1 Change in Fracture Penetration After Shut-in A varying fracture length after shut-in will affect the basic pressure decline analysis. The effect of length change is illustrated in Fig. 38, which shows an initial slope greater than the slope at closure. The early rapid decline results from fluid flow past the fracture tip at shut-in, that is, fracture extension after shut-in. The fracture length will then recede toward the wellbore during closing. The slope will decrease as high leakoff area is lost. Fig. 38 shows the G-plot for this case, which clearly indicates a significant reduction in slope with time. The correct value of leakoff can be obtained by applying a correction to the standard “G” plot. Corrected slope m′G = fcmG, Where: fc = correction factor mG = slope of the G-plot near closure. fc =



β' βs



1 + ∆t D f ( ∆t D )



1/ 2 f ( ∆t D ) = 2[(1 + ∆t D )1/ 2 − ∆t D ] for α = 1



f ( ∆t D ) = sin − 1 (1 + ∆t D ) − 1/ 2



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Values of fc are provided in Table 5. The features of the G-plot also indicates that the correct value of p* can be obtained dA f at the transition between extension and recession, that is, when: = 0 at the end dt ∆pw ≈ 3 / 4 (with of extension. The transition from extension to recession occurs at ∆ps ∆ps = net pressure immediately after shut-in) and resulted in suggestion of a “3/4 rule” to eliminate the effect of penetration changes during shut-in; that is, select p* as the value of mG at ∆pw = 3/4 ∆ps as shown in Fig. 38.



Fig. 38. Penetration change during shut-in (after Nolte, 1990). 4.3.5.2 Height Growth Height growth will reduce the rate of pressure decline during initial shut-in. During this period, the decreasing height dispels fluid into the primary fracture and creates an equivalent flow rate source. This flow rate source delays the closure time. This period will last until the net pressure decreases to about 0.4∆σ for the barrier and provides a height growth diagnostic (Fig. 39). The transition to a greater decline after the height growth closes provides the period of the decline analysis similar to the case of no growth. Applying the correction to the slope near closure provides correct estimate of p* (the similar correction for the case of length recession). Fig. 39 also suggests the governing stress barrier difference can be defined from the Gplot;



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∆pknee with ∆pknee the net pressure at the “knee” of the dog-leg. 0.4



Fig. 39. Diagnostic for height growth from decline data (after Nolte, 1990). 4.3.5.3 Pressure-Dependent Leakoff There are two mechanism for the pressure-dependent fluid loss. 1.



stress-sensitive fissure



2.



filtrate - and reservoir-control mechanism



Stress-Sensitive Fissures For the stress-sensitive fissures, the governing pressure is the difference between principal horizontal stresses (∆σH, see Section 4.2.2.2). During a fracture treatment, the pressure within the fissure increases as fluid leaks off into it. The effective normal stress on the fissure decreases and its permeability increases. The permeability and fluid loss are enhanced throughout the treatment, with the effect accelerating as the pressure increases. If the pressure continues to increase, the pressure in the fissure can become greater than the normal stress, the fissure will open and the leakoff is further accelerated. At this time, the pressure capacity is reached and regulates the pressure at a constant value. The diagnostic for the stress-sensitive fissure as shown in Fig. 40 is a progressively decreasing log-log slope on the Nolte-Smith plot during pumping until the pressure capacity is reached (that is, showing constant pressure condition) and a progressively decreasing slope on the G-plot (positive curvature) during decline DOWELL CONFIDENTIAL



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period. Height growth can also produce a constant pressure condition similar to fissures; however, height growth (Fig. 39) provides negative curvature (increasing slope) on the G-plot; the distinguishing diagnostic for fissures relative to height growth.



Fig. 40. Diagnostic for stress sensitive fissures from injection and decline (after Nolte, 1990).



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The pressure behavior of stress-sensitive fissures is more complex than filtrate- or reservoir-controlled fluid loss. Numerical simulations are required to properly asses this effect. The value of the leakoff coefficient is best determined by pumping pressure history match, using an appropriate fracture simulator. To approximate CL ∆pw ≈ 3 / 4 that is, when the from the G-plot, the slope of the G-plot is selected at ∆ps area is constant and with a high value of net pressure so the effect of fissures dominates the fluid loss.



Filtrate- and Reservoir-Controlled Mechanism If leakoff is controlled by the filtrate viscosity (Cv) or by reservoir permeability and compressibility (Cc), the leakoff is pressure dependent. No significant pressure dependence is expected for a wall-building fluid. For the filtrate- and reservoircontrol fluid loss, the governing pressure is the difference between fracturing pressure (pf) and reservoir pressure (pr). This mechanism is significantly affected by pressure change during decline as shown in Fig. 41. The figure shows the G-plot found by numerical simulation and indicates a significant reduction in slope with time, that is, mG < p* at later stage of closure. Using the fracture simulator, the leakoff coefficient was found to be approximated by the slope of the net pressure at ∆pw ≈ 3 / 4 as shown in Fig. 41. ∆ps



Fig. 41. Decline analysis for filtrate and reservoir control leakoff (after Nolte, 1993).



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4.3.5.4 Spurt Spurt (Sp) is the fluid volume lost during the formation of a filter cake. It is negligible for low-permeability formations (less than one md). The rate of spurt is controlled by the filtrate (Cv) and reservoir fluid (Cc) during the spurt period (tsp). Generally, spurt is negligible after shut-in since the new area exposed is small; therefore, spurt loss has a negligible effect on the pressure decline and cannot be defined from the pressuredecline analysis. For large values of spurt (which can occur at high ∆p or in high-permeability formations without using effective fluid-loss control additives), the large spurt time and volume can affect the decline analysis. Spurt will affect the pressure-decline analysis based on the “3/4” rule if the spurt time is greater than the time at ∆pw ≈ 3 / 4 . It can be shown from the volume balance relation at shut-in that the ∆ps spurt will not affect the decline analysis if; tsp κη < . ti 4(1 − η) Although the spurt generally does not influence the decline analysis using the “3/4” rule, the magnitude of spurt during injection may be important and must be characterized. The effect of spurt can be eliminated for the treatment by performing a calibration treatment of a size comparable to the treatment and using effective fluid-loss control additives. The spurt can be estimated from the laboratorySp determined ratio of for representative formation and fluid samples. Assuming CL the ratio is the same in the laboratory and field, Sp can be defined by using CL from Sp calibration treatment and keeping the ratio of constant; CL Spurt correction κ = 1 +



Sp go C L ti



The spurt correction κ is used to account for additional fluid loss due to spurt. The effective fluid-loss coefficient during pumping = κCL. 4.3.5.5 Closure Pressure Change The closure pressure is assumed constant in the basic pressure-decline analysis. Leakoff of the fracturing fluid under high pressure will cause an increase of the closure pressure because of poroelastic effect. Although not common, evidence of increased closure pressure with injection time has been reported in the field. The poroelastic stress changes have little effect on fracture geometry, but the pressure is increased by an amount approximately equal to the stress change during injection or decline.



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The most significant stress changes occurs for the PKN model. The upper bound of the stress change for this case; ∆σ ≈



2.64 MC L t φct h



    kt   M ≈ 1 − 0.6 2   φµct  h    2   



1/ 4



The equation indicates that the stress change is proportional to the fluid-loss coefficient, and hence depends on the controlling fluid-loss mechanism, that is, wall cake (Cw), filtrate viscosity (Cv) or reservoir control (Cc). The analysis by Nolte has shown that this closure stress change is bounded by a maximum for constant CL (Cw controlled or small ∆pf) and a minimum for Cc. Fig. 42 shows the wellbore stress change for Cc = 0.001 ft / min and 0.002 ft / min.



Fig. 42. Stress change during injection/shut-in for Cc (after Nolte et. al., 1993).



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The rate of change of ∆σ; d∆σ 1.32 M 2C L ≈ . dt φct h t The rate of stress change decreases with time. When stress changes are significant, the closure pressure test should be conducted immediately after the decline of the calibration treatment instead of before the treatment. Fig. 42 indicates that the stress change is generally positive; the stress continues to increase during pumping and after shut-in. This would result in an underestimate of CL. A conservative estimate of CL can be obtained from the inferred CL as follows; 0.43   C' L = C L 1 + φ ct E'   4.3.5.6 Compressible Fluids Most fracturing fluids can be assumed to have constant density since they are relatively incompressible compared to the elastic response of the fracture. The basic pressure-decline analysis assumes that the fluid density is constant (incompressible). Foams, however, are much more compressible than liquids. The foam density change can have an effect on the pressure-decline analysis and must therefore be considered. When the fracturing fluid is compressible and significant warming of the fracturing fluid occurs after shut-in, the thermal expansion of a compressible fracturing fluid will affect the pressure behavior during decline. The analysis indicates that the pressure of a compressible fluid will decline at a slower rate compared with an incompressible fluid (decrease the slope of the G-plot). The fluid-loss coefficient will therefore be underestimated. The effect of foam fluids on the decline analysis is expressed in terms of the ratio of ∆Vg ∆Vg the change in gas volume to fracture volume, denoted as . The value of ∆V f ∆V f is governed by the effect of temperature and pressure of the compressible fluid. Fig. 43 shows a simulation for an extreme case (foam fracturing of hot, shallow formations) using a fracture simulator; a case of high temperature, high efficiency and low closure pressure to illustrate the large effect on the gas volume increase. For this case the error is about 13% for the fluid-loss coefficient obtained by the “3/4” rule.



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Although the effect for the increase in gas volume of the compressible fluid during shut-in is small, a correction factor can be applied to the inferred CL. The correction term is provided in SPE 25845 (Nolte et al, 1993) and is a relatively complex relation.



Fig. 43. Relative volume change of gas (after Nolte et. al., 1993). 4.3.6 Fluid Efficiency Based on Pressure Analysis The expressions for fluid efficiency in Section 4.3.3 and Section 4.3.4 define this parameter in terms of dimensionless closure time for ideal behavior with or without spurt. These expressions can be generalized for non-ideal behavior by defining the efficiency in terms of shut-in net pressure (∆ps) and match pressure (p*). The fluid efficiency can be expressed as follows; Vf Vf Af w η= = = . Vi VLP + V f 2κgo C L rp A f t p + A f w From the relationship of width and pressure directly after shut-in (w = cf ∆ps), and 2c f p * CL = , πrp t p



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η=



with go ≈



A f c f ∆ps 4 κA c p * go + A f c f ∆ps π f f



Section 700.1 May 1998 Page 73 of 81



,



π , 2 η≈



∆ ps , 2κp * + ∆ps



η≈



G* , 2κ + G *



∆ps . For ideal conditions, G* = Gc and the expression for efficiency p* becomes as in Section 4.3.4. For non-ideal behavior, p* ≠ mGC and G* ≠ Gc. Because the ideal assumptions are not generally valid, the closure point is not a reliable predictor for efficiency. where G* =



4.3.7 Decline-Analysis Procedure As discussed in the previous section, the corrections can be provided for violating the basic assumptions. The non-ideal behavior is related to penetration changes, height growth, pressure-dependent fluid loss, spurt, closure pressure change, and density effects. The decline-analysis procedure is (see Fig.44): 1.



Find the slope of the “G” plot (mG) at



∆pw ≈ 3 / 4 (that is, m3/4, referred to as the ∆ps



“3/4 rule”). 2.



For the KGD and radial models, p* = m3/4



3.



For the PKN model, p* = max of { m3/4 , m′G } m’G = fc mGc where fc is the correction factor (see Table 5) and mGc is the slope near closure.



4.



Calculate CL. CL =



5.



Calculate η. η=



2c f p * πrp t p



∆p G* where G* = s 2κ + G * p*



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The correction factor (fc) is the product of



Dowell



β′ 1 + ∆t D f ( ∆t D ) and is provided in βs



Table 5. From numerical simulations, β′≈1. The decline-analysis procedure provides the following results. • For height growth without pressure-dependent fluid loss, p* ≈ m′G, In this case, m′G > m3/4. •



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For no significant height growth but pressure-dependent loss, p* ≈ m′3/4, In this case, m′G > m3/4.



Fig. 44. Decline analysis using “¾” rule (after Nolte, 1990).



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Table 5. Correction Factors fc As Function Of ∆tD ∆ tD



fc



G(∆ ∆tD)



∆ tD



fc



G(∆ ∆tD)



0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00



2.09 1.77 1.68 1.63 1.59 1.56 1.54 1.52 1.50 1.49 1.48 1.47 1.46 1.46 1.45 1.44 1.44 1.43 1.43 1.43 1.42



0.00 0.17 0.33 0.47 0.60 0.72 0.84 0.96 1.07 1.17 1.27 1.37 1.47 1.56 1.65 1.74 1.83 1.91 1.99 2.07 2.15



2.10 2.20 2.30 2.40 2.50 2.60 2.70 2.80 2.90 3.00 3.10 3.20 3.30 3.40 3.50 3.60 3.70 3.80 3.90 4.00



1.42 1.41 1.41 1.41 1.41 1.40 1.40 1.40 1.40 1.40 1.39 1.39 1.39 1.39 1.39 1.39 1.39 1.38 1.38 1.38



2.23 2.31 2.38 2.45 2.53 2.60 2.67 2.74 2.80 2.87 2.94 3.00 3.07 3.13 3.19 3.26 3.32 3.38 3.44 3.50



4.3.8 Steps to Correct Decline Analysis Using the FracCADE Software The following steps are required to correctly analyze the pressure decline from a calibration test: 1.



Ensure the decline data is good. After the data has been imported into the DataFRAC software, examine the G-plot using 'Graphics' mode to see if the data are smooth and continuous. Remove any bad initial data which included the pressures when the pumps were still rolling over. This initial data gives high net pressure and steep initial decline. Another type of bad data is not enough data points (resembling a dot-to-dot puzzle).



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Determine the analysis type to be performed on the “G” plot. For the basic decline analysis portion of the “G” plot can be condition of non-ideal behavior, the previous section can be DataFRAC software.



3.



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when the ideal assumptions hold, the linear determined using 'Manual' analysis. For the the procedure of the “3/4” rule as discussed in performed using “recession” analysis in the



Match net pressures. The last step is to match the net pressure at shut-in with the predicted net pressure from the fracture simulator using the parameters derived from the analysis of the “G” plot. The match is performed by adjusting Young's modulus (E) or gross fracture height (H) for the PKN model and adjusting E or rock toughness (K) for the KGD or radial model. This pressure match assumes ideal behavior and application of the ideal models. For non-ideal behavior, the net pressure match should be done using the Placement module in the DataFRAC software.



4.3.8.1 The DataFRAC Software The well, reservoir, rock mechanics, and fluids screens should be completed before performing the DataFRAC analysis. The Job Record Data Entry form is used to read the pressure datafile into the FracCADE software (refer to the FracCADE User's Manual for complete information). The fluid Sp and Cw values can be obtained from laboratory data or the Fracturing Materials Manual  Fluids. The ratio of Sp and Cw will be used and kept constant in calculating the new spurt based on the leakoff coefficient (CL) obtained from the analysis. The new values of Sp and Cw are used to determine efficiency. The DataFRAC analysis information should be completed to define how the analysis of the G-plot is controlled and performed. The types of analysis available in the DataFRAC program are 1.



Graphic Analysis The 'Graphic' option allows the user to look at the G-plot. It is normally used first to determine if the data set is good. This option does not perform any calculation.



2.



Automatic Analysis The 'Automatic' option requires the least amount of interaction from the user. It is used for the ideal conditions of the basic pressure decline by automatically selecting the best straight line of the G-plot. The program uses the derivative of the G-plot to look for the minimum curvature within the analysis range. The straight line selected likely will not correspond to p* and may or may not correspond to the fracture closure period.



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3.



Section 700.1 May 1998 Page 77 of 81



Manual Analysis The 'Manual' option is also used for the ideal conditions. The user supplies the maximum and minimum pressure constraints to be used for determining the straight line of the G-plot.



4.



Recession Analysis The recession analysis with “closure pressure” as the closure variable is the preferred option and uses the “¾” rule or correction to slope on the G-plot as outlined in the previous sections to account for the non-ideal behavior.



Closure Variable Closure input variables control the determination of the closure point, which indicates if closure pressure or closure time is to be specified. Using “closure pressure”, the corresponding “closure time” will be extrapolated and vice versa. The closure pressure should be determined from an independent closure test analysis (see Section 4.1). If the closure variable is not specified, the program will automatically take the last point on the straight line of the G-plot as the closure point. 4.3.8.2 G-plot Interpretation by the DataFRAC Software ∆pw ≈ 3 / 4 or at ∆ps closure) compared to the actual Initial shut-in pressure (ISIP) gives some indications of the fracture evolution. The difference should generally not be greater than 200 psi.



The value of Yint (Y intercept from the tangent line to the G-plot at



A condition in which Yint is less than the ISIP is equivalent to a positive curvature of the G-plot due to the non-ideal behavior described in the previous sections, that is, penetration change and pressure-dependent fluid loss. When Yint is greater than the ISIP, it indicates a negative curvature of the G-plot because of height growth into stress barriers. It can also be concluded that the equivalent 2D model is PKN since height growth into stress barriers is inconsistent with the basic requirements of the radial or KGD model. The inequality of Yint and the ISIP is corrected by shifting the tangent line upward or downward to intercept the ISIP. This will also allow the user to use a proper value of net pressure based on the ISIP instead of Yint for determining the efficiency and making a net pressure match with the fracture simulator. Answer “Yes” to the “Adjustment for Initial Deviation” field to perform this function. 4.3.8.3 Modulus, Height, or Fracture Toughness Calibrations The most important and uncertain parameters for a proper evaluation of the leakoff coefficient are Young's modulus, total fracture height, and fracture toughness. The values of Young's modulus obtained from the log can be crossed-checked and



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calibrated using the DataFRAC software. The fracture height for the PKN model and the fracture toughness for the KGD or radial model can also be calibrated. The procedure is to make the simulator net pressure match up with the analysis by adjusting the Young's modulus and holding other parameters constant. The gross fracture height for the PKN model and the fracture toughness for the KGD or radial model can also be adjusted until the net pressure from the fracture simulator matches that from the analysis. For the case with barriers, the preferred method is to select the height as the gross pay (or sand) section and calibrate the modulus from the DataFRAC analysis. The calibrated modulus can be much greater (that is, twice) than actual modulus to account for interbedded shales (that is, high stress zone). Compliance for each model gives an understanding as to which parameter is controlling the pressure response. The compliance for each model is cf ∝



•



PKN:



•



KGD:



cf ∝



2βx f E'



•



Radial:



cf ∝



βR E'



βh f E′



E′ = plain strain modulus



E′ = E/1 - v2



The average width is expressed in terms of fracture compliance (cf) and net wellbore pressure (∆pf), that is, w = cf ∆pf. This indicates that both total fracture height and Young's Modulus have a large impact on net pressure for the PKN model. For the KGD and radial models, Young's Modulus has an impact on pressure. The fracture width and length (xf or R) are also affected by fracture toughness for the KGD and radial model. The fracture toughness will therefore have an important effect on net pressure for these models. In a 1991 publication, Nolte incorporated toughness in the PKN model. The β factor, and therefore, the pressure is affected by the toughness. The pressure matching using toughness for the PKN model has not been implemented in the DataFRAC software because the PKN pressure is not very dependent on the tip behavior. 4.3.8.4 The β Ratio The β ratio is the ratio of the average net pressure in the fracture and the wellbore net pressure; ∆p f p f − pc β= = ∆p f pw − pc



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This parameter is necessary for volumetric calculations of the fracture in terms of the pressure value at the wellbore. The analysis of fluid flow in the fracture indicates there is a gradient of pressure from the maximum value at the well, pw, to the minimum value at the fracture tip, approximately pc. Fig.45 shows an example of the pressure and flow profiles during pumping and after shut-in using the PKN model.



Fig. 45. Pressure and flow rate in fracture before and after shut-in (after Nolte, 1986). The value of β during pumping (βp) differs from the value of β after shut-in (βs). During pumping,



βp ≈



n' +2 n' +3



β p ≈ 0.9



PKN KGD and Radial



During shut-in, βs ≈



2n' +2 2n' +3



β s ≈ 0.95



PKN KGD and Radial



βs and βp are used to convert the net pressure at shut-in (∆ps) to the net pressure at the end of pumping (∆pp); β ∆p p = s ∆ps . βp



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The net pressure at the end of pumping is used by the DataFRAC program in the net pressure matching to calibrate Young's modulus, total fracture height, or fracture toughness. 4.3.9 Post Proppant Fracture Analysis The “G” plot analysis after the propped fracture treatment can provide information on the effectiveness of the fracture treatment. The effectiveness is indicated by the ratio of net pressure at closure on proppant to net pressure at shut-in; w prop ∆p prop = ∆ps whyd If fracture closure did not occur until most of the net pressure was lost (that is, ∆pf = 0), very little of the fracture width was propped and hence, the job was not effective.



Fig. 46. Diagnostic for closing on proppant from decline data (after Nolte, 1990). The closure on proppant will change the rate of pressure decline, that is, with significant slope change. Fig.46 illustrates the effect of fracture closing on proppant. Two cases affect the pressure decline behavior after closure. 1.



Decrease in rate of pressure decline. A decrease in the rate of pressure decline is indicative of a relatively impermeable proppant-pack caused by unbroken fluid and the filter cake impairing communication between the fracture and the wellbore. DOWELL CONFIDENTIAL



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2.



Section 700.1 May 1998 Page 81 of 81



Increase in rate of pressure decline. An increase in the rate of pressure decline indicates the fracture system stiffening during closure on a permeable pack communicating freely with the well after closure.



Although the initial closure period may be relatively free of the effects of proppant, the G-plot may be different from the representative condition and any analysis could be subject to a high degree of uncertainty. Therefore, an unpropped calibration treatment is always preferred over a propped fracture pressure decline; but for obtaining some insight into a failed treatment, the decline from the treatment can be used to infer the fluid-loss coefficient. The effect of proppant or the inference of efficiency is discussed in Section 4.3.3. 4.3.10 References Comprehensive discussion of fracturing pressure analysis are provided in the following publications: 1.



Nolte, K.G.: Fracturing Pressure Analysis, Recent Advances in Hydraulic Fracturing, J. Gidley et al. (eds.), Monograph Series, SPE, Richardson, TX (1989) 12, Chap. 14.



2.



Nolte, K.G. and Economides, M.J.: Fracturing Diagnosis Using Pressure Analysis, Reservoir Stimulation, second edition, Prentice Hall, Englewood Cliffs, NJ (1989) Chap. 7.



3.



Nolte, K.G.: “Fracturing Pressure Analysis for Nonideal Behavior,” JPT (Feb., 1991) 210-18.



4.



Nolte, K.G.: “A General Analysis of Fracturing Pressure Decline With Application To Three Models,” SPEFE (Dec. 1986) 571-83.



5.



Nolte, K.G., Mack, M.G. and Lie, W.L.: “A Systematic Method For Applying Fracturing Pressure Decline, Part 1,” SPE 25845, Denver (April 1993).



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Foam Fracturing



Section 700.2 May 1998 Page 1 of 30



FOAM FRACTURING 1 Introductory Summary............................................................................................................. 2 1.1 Foam Properties .................................................................................................................. 3 1.2 Foam Types ......................................................................................................................... 3 1.3 Foam Stability ...................................................................................................................... 4 1.4 Applications.......................................................................................................................... 4 2 Design ....................................................................................................................................... 4 2.1 Choosing a Foam................................................................................................................. 4 2.1.1 The Liquid Phase........................................................................................................ 5 2.1.1.1 Linear Polymers ............................................................................................... 5 2.1.1.2 Crosslinked Polymers ...................................................................................... 6 2.1.1.3 Hydrocarbons and Alcohols ............................................................................. 7 2.1.2 The Gas Phase........................................................................................................... 7 2.1.2.1 Gas Behavior ................................................................................................... 9 2.1.2.2 Gas Solubility ................................................................................................. 10 2.1.3 Foaming Agent Selection.......................................................................................... 11 2.1.3.1 Material Compatibility with Foaming Agents .................................................. 11 2.2 Foam Rheology.................................................................................................................. 12 2.3 Fluid-Loss Properties ......................................................................................................... 13 2.3.1 Two-Phase Behavior of the Foam ............................................................................ 13 2.3.2 Wall-Building Effects................................................................................................. 13 2.4 Conductivity Damage ......................................................................................................... 14 2.5 Foam Quality...................................................................................................................... 16 2.6 Foam Texture..................................................................................................................... 19 2.7 Proppant Compensation .................................................................................................... 19 2.7.1 No Proppant Compensation ..................................................................................... 20 2.7.2 Constant Bottomhole Quality .................................................................................... 21 2.7.3 Decreasing Bottomhole Quality ................................................................................ 21 2.7.4 Constant Internal Phase ........................................................................................... 22



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2.8 Friction Pressure ................................................................................................................22 2.9 Yield Stress ........................................................................................................................23 2.10 Limitations of Application..................................................................................................23 2.11 Job Design........................................................................................................................23 2.12 Calculations ......................................................................................................................23 2.12.1 Pressures and Rates...............................................................................................23 2.12.2 Equipment Requirements........................................................................................25 2.12.3 Material Requirements ............................................................................................26 3 Execution ................................................................................................................................26 3.1 Foam Generation ...............................................................................................................28 3.2 Material Balance.................................................................................................................30 FIGURES Fig. 1. The effect of polymer loading on foam viscosity (50% quality foam).................................5 Fig. 2. The effect of various polymers on foam stability. ..............................................................6 Fig. 3. The effect of foam quality on viscosity (StableFOAM fluid). ............................................12 Fig. 4. Leakoff of a foam into the rock matrix. ............................................................................13 Fig. 5. Dimensionless polymer concentration factor...................................................................15 Fig. 6. Polymer concentration versus proppant-pack retained permeability...............................16 Fig. 7. Bubble arrangements for various foam-quality ranges....................................................17 Fig. 8. Proppant concentration limits in foam fluids. ...................................................................18 Fig. 9. The effect of proppant compensation methods on bottomhole foam quality. ..................20 Fig. 10. Friction through perforations. ........................................................................................25 Fig. 11. Schematic of foam fracturing treatment.........................................................................27 Fig. 12. Laminar and turbulent flow areas of foamed fluids........................................................29 Fig. 13. Foam generator.............................................................................................................29 TABLES Table 1. Summary of Foam Fracturing Fluids ..............................................................................3 Table 2. Comparison of Nitrogen and Carbon Dioxide.................................................................7 Table 3. Proppant-Pack Porosity of Sand and Intermediate-Strength Proppant ........................15



1 Introductory Summary A foam fracturing fluid is a stable emulsion composed of a liquid (external or continuous) phase surrounding a gas (internal, dispersed, or non-continuous) phase and a surfactant (foaming agent). Foam fracturing fluids are characterized by their “quality.” The quality of a foam (Q) is defined as the ratio of gas volume to the liquid and gas volume. DOWELL CONFIDENTIAL



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Q=



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Vg Vg + VL



Vg is the volume of the gas-phase and VL is the volume of the liquid-phase. The liquid ratio of the total foam is then 1 - Q. Section 2.5 provides a discussion on foam quality. 1.1 Foam Properties Foam fracturing fluids, as compared to nonfoam fluids, are particularly well suited for fracturing because of some very unique properties. These include: • stored compressed gas for better cleanup •



good fluid efficiency



•



low fracture conductivity damage



•



equivalent rheological performance at reduced polymer loading.



1.2 Foam Types The most common and most versatile types of foams are aqueous-base foams containing a polymer in the liquid phase and nitrogen as the gas phase. Foams containing alcohol, oil or carbon dioxide are used to improve performance based on a specific requirement. A summary of foam fracturing fluids is provided in Table 1.



Table 1. Summary of Foam Fracturing Fluids Name



Liquid Phase



Advantages



StableFOAM



Water or Polymer Solution



Good overall use, easy to mix, cost effective, good rheology, good fluidloss properties and stability.



SuperFOAM



Crosslinked Polymer



High viscosity, stable at low-foam qualities for higher proppant concentrations or higher hydrostatic pressures.



Alcoholic



20% to 40% Alcohol



Less retained water on formation, and better cleanup particularly in dry, low-water formations.



Stable-Oil- Foam



Gelled or Ungelled Hydrocarbon



No water for water-sensitive formations.



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1.3 Foam Stability Foam stability is critical to the foam performance in the fracture. Stability maintains the dispersion of the gas in the liquid which in turn controls the rheology and fluidloss properties of the foam. Factors affecting stability are: • surfactant type •



surfactant concentration



•



foam quality



•



polymer type and concentration



•



mixing energy.



The stability of a foam is normally measured under static conditions at low temperature and pressure. These laboratory tests do not represent the actual downhole stability and only serve as a guide to determine which polymer or surfactant offers the most stability. 1.4 Applications Foam fracturing fluids perform best in the following applications. • depleted or underpressured wells •



water-sensitive formations



•



low-permeability gas wells.



2 Design A foam is a stable dispersion of a gas in a liquid. An unstable dispersion is also a foam, but only for a short period of time. Once segregation of the phases occurs, the properties of the foam also disappear and the fluid becomes only an energized fluid. Three conditions are necessary to create a stable foam. • A foaming surfactant at sufficient concentration and free of contaminants must be used. •



The liquid and gas must be in the proper ratio. Segregation between the liquid and gas phases will readily occur if an insufficient quantity of gas is present. The foam may invert to a mist with the gas as the outside phase if too much gas is present.



•



The mixing energy must be sufficient to create the foam.



2.1 Choosing a Foam Starting with the simplest, most versatile foam is the best approach when choosing a foam fluid for a specific application. If a deficiency exists because of a limitation in



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Foam Fracturing



Section 700.2 May 1998 Page 5 of 30



the first choice, then a modified foam fluid that addresses the deficiency is more appropriate. 2.1.1 The Liquid Phase Water without a polymer is not commonly used as the liquid phase because of limited stability. Enhanced stability can be achieved by adding a polymer, increasing the polymer concentration or by crosslinking the polymer. While crosslinked polymers exhibit the greatest stability because of their high viscosity, linear polymers are also very good at stabilizing the foam. 2.1.1.1 Linear Polymers The presence of a polymer in the liquid phase of a foam substantially increases the foam viscosity. The foam stability is directly dependent on the viscosity of the liquid phase. The greater the viscosity, the less drainage of liquid from the bubble and therefore the more stable the foam. Enhanced stability of the foam results in much more efficient and reliable proppant transport. Fig. 1 illustrates the effect of polymer loading on foam viscosity. A foam without a polymer exhibits very low viscosity (less than 5 cp at 175°F [79°C]). The need for polymer in the foam is even more evident as temperature increases.



Fig. 1. The effect of polymer loading on foam viscosity (50% quality foam). DOWELL CONFIDENTIAL



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Polymer Types Fig. 2 illustrates the effect of various polymers on foam stability. Guar, hydroxypropylguar (HPG), hydroxyethylcellulose (HEC) and xanthan gum are the most commonly used polymers. The half-life of a foam is the time necessary for one-half of the liquid phase to break out of the foam under atmospheric conditions. Half-life measurements are used only as qualitative indicators of foam stability in the laboratory. Foam half-life is much longer in the fracture under high-pressure conditions. A 75% quality foam without polymers generally yields a half-life of less than five minutes. Addition of polymers increases the half-life of the foam substantially. Of the available polymers, xanthan gum is the most efficient and can be used at much lower concentrations than other polymers.



Fig. 2. The effect of various polymers on foam stability. 2.1.1.2 Crosslinked Polymers A crosslinked polymer in the liquid phase allows the gas content to be decreased which results in a larger hydrostatic pressure and lower surface treating pressure. However, the viscosity of the crosslinked liquid phase is greater than the linear liquid



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phase which increases the friction pressure and may reduce some of the benefits of the lower treating pressure. The major advantage of using a crosslinked foam is the ability to achieve higher proppant concentrations in the fracture. Assuming the maximum proppant concentration at the blender is 20 PPA, the maximum proppant concentration in an uncrosslinked 70% quality foam is approximately seven pounds proppant added (PPA) because all of the proppant must be added to the liquid phase (30% of the foam). Because the gas content is lower in a crosslinked foam, typically a 30% quality foam, the maximum proppant concentration can be higher (15 PPA). Treatment design may allow a lower foam quality in later stages of a treatment to achieve higher proppant concentrations. 2.1.1.3 Hydrocarbons and Alcohols Hydrocarbon foams containing carbon dioxide are impractical due to the high solubility of the carbon dioxide in the oil. Hydrocarbons foamed with nitrogen are costly fluids because of the fluorocarbon surfactants required to make a stable foam. Alcohol (chiefly methanol) foams can be used in dry gas reservoirs to prevent relative permeability problems. Specific limits for the alcohol content in the aqueous phase are provided in the Dowell Location Safety Standards. 2.1.2 The Gas Phase Nitrogen and carbon dioxide are the gases most commonly used in foam fluids. Formation characteristics, fluid compatibility and economics are major factors that are considered during the decision-making process. Nitrogen is an inert gas, and is the most frequently used because it is versatile. Carbon dioxide is more soluble in water than nitrogen so more carbon dioxide is required to saturate the liquid and create the foam. Table 2 provides a comparison of nitrogen and carbon dioxide.



Table 2. Comparison of Nitrogen and Carbon Dioxide Property



Nitrogen



Carbon Dioxide



Hydrostatic Head



Low



High



Reactive



Inert



Yes



Solubility in Water



Low



Moderate



Solubility in Oil



Low



High



Surface Tension Reduction



None



Good



Compressibility



High



Low



Temperature



100°F (38°C)



20° to 40°F (-7° to 4°C)



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In certain applications, carbon dioxide may have an advantage. These include: • greater hydrostatic pressure (liquid carbon dioxide is more dense than nitrogen) resulting in lower treating pressure •



more expansion during flowback (aids in total fluid recovery)



•



may prevent or remove water blocks.



The solubilized portion of carbon dioxide reduces the interfacial tension of the fracturing fluid to levels as low as those obtainable by many surfactants. Carbon dioxide has an advantage in that the carbon dioxide is soluble in the water whereas the surfactant may loose its efficiency by absorbing onto the rock surfaces. This becomes more critical in tight and low-pressure formationsprimary candidates for foam fracturing fluids. Carbon dioxide is extremely soluble in oil. Stable-Oil-Foams normally use nitrogen as the gas phase when the foam quality is greater then 50%. Fluids that are saturated with carbon dioxide have low interfacial tension which reduces capillary pressure and damage. Carbon dioxide also reduces the viscosity of formation oils and gives an initial production “kick.” This is of little consequence to long-term production but gives the appearance of high production. However, at the same time care must be taken to ensure that the carbon dioxide and the relatively large proportion of surfactants pumped into the formation do not create emulsions that could damage the permeability and reduce productivity. Carbon dioxide, unlike nitrogen, is not compatible with all liquid phases. Carbon dioxide is not recommended in the following fluids. • YF100, YF100D, YF200, YF200D, YF500HT, YF600LT, and YF600HT. Carbon dioxide will interfere with the crosslinking mechanism by lowering the fluid pH value. •



Stable-Oil-Foam. Carbon dioxide is highly soluble in Stable-Oil-Foam and will reduce the viscosity of the hydrocarbon.



Carbon dioxide is easily dispersed in the YF300LPH and YF400LPH series of fluids. The pH buffer contained in the crosslinker solution maintains a constant fluid pH value of approximately 4, which simulates a saturated carbon dioxide environment. Consistent fluid performance is ensured despite variations in the carbon dioxide concentration or complete loss of carbon dioxide during job execution. Carbon dioxide is pumped at the wellhead in liquid form. The mixture of aqueous fluid and liquid carbon dioxide, although not a foam by definition, forms a two-phase emulsion which has properties similar to foam. The critical temperature (triple point) of carbon dioxide is approximately 88°F (31°C). Carbon dioxide is a supercritical fluid commonly referred to as a gas at temperatures greater than 88°F (31°C). The transition from liquid to supercritical fluid does not affect the physical properties of either the carbon dioxide or the foam provided the treating pressure is greater than 1080 psi, the critical pressure of the carbon dioxide. DOWELL CONFIDENTIAL



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Section 700.2 May 1998 Page 9 of 30



Halliburton Services holds patents for exclusive use of 53% to 96% quality foams made with carbon dioxide. Dowell is licensed to use these foams with payment of license fees (USA and Canada only).



Binary Foam Binary (dual-gas) foam is not subject to the Halliburton patent, as long as the carbon dioxide content remains below 53%. The carbon dioxide phase in a binary foam is usually held constant at 50% quality with the remainder made up of nitrogen. 2.1.2.1 Gas Behavior The behavior of gases at given pressures and temperatures is predictable by use of the ideal gas law and the gas deviation factor. Eq. 1 illustrates the ideal gas law. PV = nRT



(1)



Where: P = pressure (psi) V = volume (ft3) n = number of moles (lbm/molecular wt of the gas) T = temperature (°R)  ft 3 psi  R = universal gas constant:  10.73 T  . n   Eq. 1 is true for moderate pressure (less than 500 psi) and low temperature. When pressure and temperature are increased, the actual volume that the gas will occupy deviates from the prediction of the ideal gas law. The gas law can be corrected by the use of the “Z” factor (gas deviation factor or compressibility factor). Each gas has a different value for Z at a given pressure and temperature because Z is based on the critical pressure and critical temperature. The critical pressure and critical temperature are distinctive properties of a specific element. For nitrogen, Z will generally range from 0.8 to 1.9. A value of 1.0 assumes ideal behavior (no deviation from PV = nRT). Eq. 1 can be rewritten as PV = ZnRT to correct for the volume change. If temperature or pressure is held constant and the other is varied, the number of gas molecules required to fill a unit volume changes. An increase in temperature decreases the number of molecules required to fill a unit volume when pressure is constant. An increase in pressure increases the number of molecules required to fill a unit volume when the temperature is held constant. By manipulating the ideal gas law, the change in volume can be predicted.



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Example Psc Vsc PV = Z sc Tsc ZT thus, V=



PscVsc ( ZT ) = ft 3 Tsc Z sc P



subscript "sc" means standard conditions. If the values for standard conditions (14.7 psi and 60°F) are substituted in the example and Vsc is assumed to be equal to unity, then the equation becomes Eq. 2.  P 198.6   = scf / bbl  ZT 



(2)



Where: P = pressure (psi) T = temperature (°R) Z = gas deviation factor (dimensionless). Volume factors and gas deviation factors are provided in the Nitrogen Engineering Handbook and A Practical Companion to Reservoir Stimulation, Section P. Obviously, an accurate value for bottomhole fracture pressure is critical because all compressibility calculations are based on this value. Nitrogen and carbon dioxide occupy a different amount of space for any given pressure. The volume of these gases must be calculated at fracturing pressures. Changing the amount of gas pumped based on surface pressures during a treatment will almost always lead to an error in the downhole foam quality. 2.1.2.2 Gas Solubility Nitrogen and carbon dioxide are soluble in the liquid phase (refer to Table 2.). In water, the amount of gas lost to the solution is generally considered not significant when calculating gas volumes. In oil, the carbon dioxide solubility is high and the amount of gas lost to solution should be accounted for. The FracCADE* software considers gas solubility in the foam calculations. The total volume of gas needed for the quality calculation is the sum of the volume of the gas at fracturing conditions and the solubility. Gas solubilities of nitrogen and carbon dioxide in crude oil and water are provided in A Practical Companion to Reservoir Stimulation, Section P.



*



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Section 700.2 May 1998 Page 11 of 30



2.1.3 Foaming Agent Selection The foaming agents that are typically used in foam fracturing fluids are: • EZEFLO∗ F40 Surfactant •



Foaming Agent F52.1



•



EZEFLO F78 Surfactant



•



a F78/EZEFLO F75N Surfactant Mixture.



Selection of a foaming agent is usually determined by the type of foam fracturing fluid and the foaming agent compatibility with the formation fluids. Testing of the foaming agent with the formation fluids is strongly recommended prior to performing the fracturing treatment in an unfamiliar area. 2.1.3.1 Material Compatibility with Foaming Agents Materials that contaminate and inhibit the performance of the foaming agents should be avoided. These include: • antifoam agents or defoamer •



hydrocarbons (as additives or in the formation)



•



heavy brines (including formation brines)



•



alcohols



•



mutual solvents.



Foaming agents can tolerate contaminants in concentrations of one to three percent in the aqueous phase. Compatibility testing is recommended prior to using any materials that inhibit the performance of the foaming agent.



Formation Fluids Formation fluids may not only affect the performance of the foam but can also create an emulsion block in the formation.



Polymer Slurries F78 and clay stabilizers such as Clay Stabilizer L55 are not recommended additives in a foam fracturing fluids containing HPG Polymer Slurry J876, PSG Polymer Slurry J877, or diesel-base slurries (for example, fluid-loss additive slurries). A loss in foam stability may occur with some field mix-waters. Laboratory testing should be performed prior to using F78 or clay stabilizers in a foam fracturing fluid containing J876, J877, or diesel-base slurries. Diesel-base slurries should always be used with caution when preparing a foam fracturing fluid. The diesel phase can be detrimental to the foam stability in some ∗



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mix-waters. Thorough prejob testing must be performed using field mix-water prior to pumping to ensure foam stability. 2.2 Foam Rheology The rheology of a foam is dependent on many factors, the most important being; • foam quality •



foam texture and/or mixing



•



temperature



•



liquid-phase composition (polymer type and concentration).



Foam quality (discussed in Section 2.5) affects the shape and strength of the bubble interface structure which in turn affects the viscosity of the foam. The effect of foam quality on viscosity is illustrated in Fig. 3. Foam texture is the average bubble size and bubble-size distribution. A foam with smaller average bubble sizes has more interfaces formed, and therefore has a higher viscosity. Also, the more uniform the bubble sizes, the higher the foam viscosity. Foam texture and its dependence on controllable factors including mixing energy is discussed in Section 2.6 and Section 3.1.



Fig. 3. The effect of foam quality on viscosity (StableFOAM fluid).



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Section 700.2 May 1998 Page 13 of 30



2.3 Fluid-Loss Properties Foam fracturing fluids can have two mechanisms of fluid loss in effect, two-phase behavior of the foam and wall-building effects. 2.3.1 Two-Phase Behavior of the Foam The most common fluid-loss-control mechanism associated with foam fracturing fluid is the two-phase behavior of the foam. This two-phase effect helps control fluid loss by increasing the flow resistance of the foam through the matrix of the rock. The structure of the foam remains intact while flowing through a pipe or in the fracture. However, the structure of the foam must deform to flow into the formation. The deformation creates resistance and is illustrated in Fig. 4. The bubbles must deform to leak off into the rock matrix which has small openings (smaller than the bubble size). This deformation requires much more energy than the leakoff of a fluid with a single-phase behavior. The two-phase fluid-loss control mechanism is lost once the pore throat-size of the formation exceeds the bubble size. Based on laboratory tests, this occurs at a permeability of approximately 30 to 50 md. Above this range, foams exhibit poor fluid-loss control.



Fig. 4. Leakoff of a foam into the rock matrix. 2.3.2 Wall-Building Effects A foam containing a polymer can control fluid loss by filter-cake deposition on the fracture face. This is particularly true for low-quality foams or foams containing high concentrations of polymer. Anytime a wall-building polymer such as guar or HPG is used, there is some degree of filter-cake deposition. Wall-building properties of foam that contain low concentrations of polymer or high-quality foams are slow to develop. DOWELL CONFIDENTIAL



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In small treatments, the treatment may be finished before the filter cake is thick enough to have a significant effect on the fluid loss.



Methodology Foam leakoff is fluid-phase dominated. The leakoff values for foams are lower than the leakoff values of crosslinked water-base fluids containing diesel as a fluid-loss additive in low permeability (27 [>5.1]



[2.7]



12/20 mesh



15 [1.9]



--



[1.5]



20/40 mesh



8 [1.5]



>17 [>3.7]



--



16/20 mesh



6 [1.8]



16 [4.4]



12/20 mesh



2 [1.1]



4 [2.9]



--



18/30 mesh



[1.6]



--



--



16/20 mesh



[2.3]



--



--



[3.4]



--



--



Sand



Carbolite



Bauxite



AcFRAC Black 20/40 mesh



Several observations can be made from Table 2 and Table 3. The pack failure flow rates are very high. One gal/min (3.8 l/min) equals 34 B/D through the perforation (Table 3). For a 30-ft perforated zone with 120 perforations (assume only half connect with the fracture), the 20/40-mesh sand pack containing J501 would fail at 5300 B/D (2.6 gal/min/perforation). The pack failure flow rate from the fracture geometry is similar. The 4-in. (10 cm) wide fracture test cell has a failure flow rate of 1.3 gal/min for the 20/40-mesh sand pack containing J501. A 30-ft (9.2 m) high fracture having the same failure flow rate over each 4 in. of its height would fail at 3980 B/D.



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PropNET Technology



Section 700.9 May 1998 Page 9 of 32



The PropNET additive stabilizes sand, ceramic and pre-cured resin-coated proppant packs. The pack stability to flow changes with the proppant type and size. The PropNET additive appears less effective with sand sizes larger than 20/40-mesh, and with ceramic proppants. Field data with 20/40-mesh ceramic proppants (Interprop, Econoprop, Sinterball) and 12/20-mesh sand indicate that sufficient pack stability to flow is obtained to control flowback. J500 has not been as extensively tested as J501. Perforation geometry tests with J500 and 20/40-mesh sand show failure flow rates equal to J501 (2.7 gal/min). J500 is very similar to J501 in dimensions and properties, and is expected to perform in a similar manner. The fracture width behind the perforation was also varied in the perforation geometry (Table 3). The failure rate for J501 and 20/40-mesh sand increased from 2.6 gal/min to greater than 5.1 gal/min (10.2 to 17 l/min) when the fracture width changed from 0.5 in. to 2.0 in. (1.3 to 3.8 cm). The same 0.5-in. (1.3 cm) perforation was used in each test. Several tests with J501 and 20/40 sand were performed at FracTech Ltd., Sunburyon-Thames, UK The test cell was loaded with a 20/40-mesh sand with 1.5% J501 slurry to produce a pack 5.25” by 5.25” by 1” with a completely open face (5.25” by 1” - no perforation) for proppant production. The pack was shut in for 12 or 24 hr at 165°F (74°C) and 500 psi for the fracturing fluid to break. The closure stress was increased to 1000 psi for the start of flow of heated water-saturated nitrogen through the pack. The closure stress was increased along with the flow rate to correspond to increased closure stress with increased drawdown. The proppant/J501 pack was able to withstand a drawdown of 40 psi/ft (1760 psi closure) across the pack without significant proppant production. At 40 psi/ft (287 l/min gas), a channel formed through the pack (a molehole) with approximately 28% of the pack produced (Fig. 1). The arrows point to the edge of the molehole within the sand pack. Gas flow was from left to right in the photograph and closure stress was applied perpendicular to the visible face.



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Fig. 1. A molehole formed in a proppant pack of 20/40-mesh sand (FracTech test), viewed from the 5.25 in. by 5.25 in. face. The channel production caused a significant increase in pack conductivity. Following formation of the channel, the pack stabilized and sand production decreased to 0.0001g/minute (less than 40 lbm/year for a 100 ft high fracture) at 288 l/min gas flow rate. The gas flow rate was then increased to 573 l/min causing production of a small amount of proppant (20g in 9 min); However, the pack stabilized at this new flow rate and after 7 hr the sand production rate was 0.0086 g/min (7.5 lbm/day for a 100 ft high fracture). 2.2 Two-Phase Flow Experiments were performed with two-phase gas/water flow in the tube geometry. The pressure drop at proppant-pack failure is plotted as a function of percent volume of gas in the fluid (Fig. 2). Gas/water is expected to be the worst case because the surface tension difference is the highest. Note the triangle point on the graph. Surfactant was added to the water to reduce the interfacial tension. Proppant-pack stability increased by 20%. Water/oil surface tension is 20 to 60% that of water/air depending on the composition, and the two-phase flow effect will be less important than with gas/water. Note that in pure gas flow, pack strength sometimes exceeds the maximum flow and pressure drop of the test apparatus (plus symbols). A similar significant effect of two phase gas/water flow on the strength of resin coated proppant packs has been observed by R.J. Vreeburg et al.: (SPE 27382) and was attributed to higher drag forces on the proppant particles during two phase flow. DOWELL CONFIDENTIAL



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PropNET Technology



Pressure at Failure, psi/ft



Dowell



140 120 100 80 60 40 20 0



Page 11 of 32



+



+ Water/N2 Pulse Flow + : No Failure



Surfactant 0



20



40



60



80



100



Nitrogen, % Total Volume Flowing



Fig. 2. Pressure at failure versus nitrogen flow concentration. Results (Fig. 2) indicate that in the worst case, two-phase flow can lower the pack resistance to flow by 60 percent. The design criteria for flowback rates per perforation account for this reduction in proppant-pack resistance to flow. 2.3 Effective Proppant-Pack Stress Cycling There is industry concern about the ability of curable resin-coated proppants to resist cyclic stress loading (Vreeburg et al.: SPE 27382), although recent developments in RCP technology have significantly improved their stress-cycle behavior. Cyclic stress loading occurs when the well is shut-in and opened repeatedly. At shut-in, the reservoir pressure is close to the in-situ stress and the effective proppant-pack stress is low. During production, the effective proppant-pack stress is highest (in-situ stress minus bottomhole flowing pressure), and fluid is flowing through the proppant pack. The fluid pressure changes result in stress cycles on the proppant pack. The PropNET additives have been tested for stability to this type of situation in the laboratory and the field. J501 was tested for cyclic stress loading with 20/40-mesh sand and Carbolite. The tests were performed in a smaller size fracture geometry. The proppant packs containing the PropNET additive were placed in a conductivity cell (7 by 1.5 in. [17.8 by 3.8 cm]). This was in turn placed in a press. The stress on the proppant pack was cycled between 1000 and 4000 psi (6.9 and 27.6 mPa). At the higher closure stress, water was flowed through the pack to a specific pressure drop (flow rate) between 10 and 40 psi (69 to 276 kPa). The pressure drop (flow rate) for a specific test was the same for every cycle. The number of cycles at which the pack failed was recorded (Table 4). Final fracture width was 0.35 in. (9 mm).



DOWELL CONFIDENTIAL



Section 700.9



FRACTURING ENGINEERING MANUAL



May 1998



Schlumberger



PropNET Technology



Page 12 of 32



Dowell



Table 4. Failure of Proppant Packs Containing J501 in Cyclic Loading (1000 to 4000 PSI [6.9 to 27.6 mPa]) Fluid Pressure Drop



20/40-mesh Sand



20/40-mesh Carbolite



10 psi



>30 cycles



>30 cycles



22 psi



14 cycles



--



40 psi



15 cycles



--



Table 4 shows that proppant packs containing the PropNET additive appear to be stable to cyclic loading over several different flowing pressure drops. A field test was performed in south Texas. A well fractured using J501 was repeatedly shut-in and opened to determine if the proppant pack was stable. This well cleaned-up and was producing dry gas. The in-situ stress was 9500 psi (65.5 mPa). The reservoir pressure was 7600 psi (52.4 mPa) The effective proppant-pack stress at shut-in was 1900 psi (13.1 mPa). The flowing well head pressure was 4200 psi (29 mPa), (effective stress 5300 psi [36.5 mPa] neglecting flowing gas friction) with 3.2 MMscf/D gas. The well was shut-in for a four-hour period and then reopened for a two-hour period. This was done four times. At the end of the shut-in cycles the well head pressure was 4800 psi (33.1 mPa). During the flowing periods no more than four tablespoons of proppant were produced in a two-hour period. 2.4 Effect of Fluid Viscosity on Proppant-Pack Stability The effect of fluid viscosity on proppant-pack stability has been examined. This is important in cases where higher viscosity oils and/or unbroken fracturing fluid flow through the proppant pack containing the PropNET additive. Tests were performed in the tube geometry with two different Newtonian fluids (sucrose/water, glycerol/water) and two different proppants (20/40-mesh sand, 16/20-mesh Carbolite). The viscosity of the fluids was varied, ranging from 1 to 500 cp. The flow rate at pack failure versus fluid viscosity is shown in Fig. 3. In Fig. 3, the failure flow rate of the pack decreases with fluid viscosity to the 2/3 power. This implies that higher viscosity fluids (at bottomhole conditions) result in lower maximum recommended flowback rates. The maximum flowback rate equation (provided in the PropNET I Additive J500 and PropNET II Additive J501 manual section in the FRACTURING MATERIALS MANUAL — ADDITIVES) accounts for fluid viscosity.



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PropNET Technology



Dowell



Section 700.9 May 1998 Page 13 of 32



EFFECT OF VISCOSITY ON PACK STABILITY PACK FAILURE FLOWRATE (bbl/d/perf.)



100



20/40 SAND SUCROSE/WATER



10



16/20 CARBOLITE GLYCEROL/WATER 1



0.1 1



10



100



1000



FLOWBACK FLUID VISCOSITY (cP or mPa-s)



Fig. 3. Effect of fluid viscosity on pack stability. 2.5 Proppant-Pack Permeability The permeability of proppant packs containing the PropNET additive were measured in the Dowell conductivity laboratory. The data are shown in Tables 5 to 11. Laboratory testing indicates proppant packs with the PropNET additive have permeability 70% or more compared to 20/40-mesh proppant packs without fibers. In 16/20-mesh and larger proppants, addition of PropNET additives can result in a 50 percent decrease in permeability compared to the proppant without fibers. Because of the inert nature of the PropNET additive, the permeability results are independent of fluid or proppant type (sand, ceramic, pre-cured resin-coated proppant). Also, the proppant packs containing the PropNET additive have the same permeability response to closure stress as proppant packs without the additive. Proppant packs containing the PropNET additive can have better or worse permeability than curable RCP packs depending on choice of proppant and fluid. For example, sand and PropNET additive at 4000 psi (27.6 mPa) closure stress may be worse than curable RCP because of sand crushing. Intermediate-strength proppant packs containing the PropNET additive would have higher conductivity than curable RCP at this closure stress.



DOWELL CONFIDENTIAL



Section 700.9 May 1998



FRACTURING ENGINEERING MANUAL Schlumberger



PropNET Technology



Page 14 of 32



Dowell



Table 5. Permeabilities of Various ISP and Curable RCP Proppant Packs (5000 psi [34.5 mPa] closure stress) Fluid Type



Proppant



J501 Conc. (wt/wt)



Polymer Conc. Temperature (lbm/1000 gal)



Perm. (Darcy)



YF130HTD



20/40 IP Plus



none



200



250°F (121°C)



145 (fit)



YF130HTD



20/40 IP Plus



1%



201



250°F (121°C)



106



YF130HTD



20/40 IP Plus



1.5%



199



250°F (121°C)



114



YF140HTD



SUPER HS



none



208



250°F (121°C)



10



YF130HTD



AcFrac BLACK



none



192



250°F (121°C)



48



Test conditions: shut-in at 3800 psi (26.2 mPa) closure for 12 hr, pressure increased to 5000 psi (34.5 mPa) for test. The fit for the control was based on 10 different points ranging from 0 to 500 lbm/1000 gal polymer loading with YF100HTD fluids and 20/40-mesh Interprop Plus.



Table 6. Permeabilities of Various Sand and Curable RCP Packs (3000 psi [20.7 mPa] closure stress, YF120LG and Enzyme Breaker J134L) Fluid Type



Proppant



PropNET Conc. (wt/wt)



YF120LG



Ottawa sand



none



YF120LG



Ottawa sand



YF120LG



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



223



175 °F (79°C)



48



1.5% J500



212



175 °F (79°C)



39



Ottawa sand



1.5% J501



195



175 °F (79°C)



50



YF120LG



AcFrac CR



none



247



175 °F (79°C)



42



YF120LG



AcFrac SB



none



282



175 °F (79°C)



49



YF120LG



SUPER LC



none



244



175 °F (79°C)



38



Table 6 shows a conductivity comparison between Ottawa sand with the PropNET additives and several curable resin-coated proppants in a fluid (YF120LG) considered to be the most compatible to curable RCPs. The fluid had an initial pH value of 9.7, and an enzyme breaker was used. Curable RCPs are known to interact DOWELL CONFIDENTIAL



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Section 700.9 May 1998 Page 15 of 32



with oxidizing breakers. Within the experimental error of the test, the PropNET additives did not reduce the permeability of the Ottawa sand, and the sand containing the PropNET additives and curable RCPs had equivalent permeability.



Table 7. Permeabilities of Precured RCP Packs (5000 psi [34.5 mPa] closure stress) Fluid



J501 Conc. (wt/wt)



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



YF100HTD



none



280



250°F (121°C)



10, 40, 41



YF100HTD



1.5%



270



250°F (121°C)



21, 30



Table 7 shows that J501 has little effect on permeability when added to a pre-cured resin-coated proppant.



Table 8. Permeabilities of 20/40-Mesh Ottawa Sand Packs (4000 psi [27.6 mPa] closure stress) Fluid



J501 Conc. (wt/wt)



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



2% KCl



none



0



250°F (121°)



116



YF130HTD



none



193



250°F (121°)



32



YF130HTD



0.5%



188



250°F (121°)



50



YF130HTD



1.5%



199



250°F (121°)



28



YF130HTD



2.5%



203



250°F (121°)



27



YF545HT



none



205



250°F (121°)



56



YF545HT



1.5%



200



250°F (121°)



31



DOWELL CONFIDENTIAL



Section 700.9 May 1998



FRACTURING ENGINEERING MANUAL Schlumberger



PropNET Technology



Page 16 of 32



Dowell



Table 9. Permeabilities of 12/20-Mesh Ottawa Sand Packs (3000 psi [20.7 mPa] closure stress) Fluid



J501 Conc. (wt/wt)



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



2% KCl



none



0



225°F (107C)



376



YF135



none



191



100°F (38°)



235



YF135



1.5%



202



100°F (38°)



157



YF340LPH



none



173



225°F (107C)



98



YF340LPH



1.5%



176



225°F (107C)



72



corn syrup



none



0



140°F (60°C)



488



corn syrup



1.5%



0



140°F (60°C)



346



Table 8 and Table 9 show that PropNET additive has a constant effect on permeability regardless of proppant type, size or fluid composition. In Table 9, corn syrup was used to show the effect of J501 on 12/20-mesh sand in fluid without polymer. It was not possible to properly mix J501 and 12/20-mesh sand in water containing 2% KCl.



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Section 700.9 May 1998 Page 17 of 32



Table 10. Permeabilities of 16/20-Mesh Carbolite Packs (4000 psi [20.7 mPa] closure stress) Fluid



J501 Conc. (wt/wt)



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



2% KCl



none



0



250°F (121°C)



700



YF130HTD



none



334



195°F (91°C)



332



YF130HTD



1.5%



269



195°F (91°C)



155



YF125LG



none



279



195°F (91°C)



435



YF125LG



1.5%



227



195°F (91°C)



261



YF240D^



none



76



170°F (77°C)



246



YF240D^



1.5%



57



170°F (77°C)



149



ClearFRAC*



none



0



195°F (91°C)



686



ClearFRAC



1.5%



0



195°F (91°C)



478



^3800 psi closure stress Table 10 shows the effect of PropNET additive on the permeability of 16/20-mesh Carbolite proppant packs. The PropNET additive gives a decrease in permeability of between 30% and 50% of that of the base depending on the fluid used.



Table 11. Permeabilities of 20/40-Mesh Interprop Plus Packs (5000 psi [34.5 mPa] closure stress) Fluid



J501 Conc. (wt/wt)



Polymer Conc. (lbm/1000 gal)



Temperature



Perm. (Darcy)



YF130HTD



none



175



250°F (121C)



164 (fit)



YF130HTD



1.5%



176



250°F (121C)



110



The effect of closure stress on Interprop Plus proppant-pack permeability is shown in Fig. 4. The proppant pack containing J500 exhibits the same behavior as the proppant pack without J500.



*



Mark of Schlumberger



DOWELL CONFIDENTIAL



Section 700.9



FRACTURING ENGINEERING MANUAL



May 1998



Schlumberger



PropNET Technology



Page 18 of 32



Dowell



800



20/40 INTERPROP PLUS



PERMEABILITY (DARCY)



700



600



500



400



300



INTERPROP PLUS WITH 1.2% PropNET I ADDITIVE J500



200 0



2000



4000



6000



8000



10000



Effective Proppant Closure Stress (psi.)



Fig. 4. The effect of closure stress on proppant-pack permeability with and without J500. Figure 5 shows the effect of PropNET level on the permeability of 12/20-mesh ceramic proppant. Corn syrup was used as the mixing fluid and the tests were performed at 4000 psi closure and 195°F (91°C). Note that reducing the PropNET level from 1.5% to 0.5% increases permeability from 77% to 87% of the control without PropNET.



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May 1998



PropNET Technology



Dowell



Page 19 of 32



PERMEABILITY (DARCY) 750 700 650 600 550 500 450 400 0.0



0.5



1.0



1.5



2.0



2.5



J501 CONCENTRATION



Fig. 5. The effect of J501 concentration on the permeability of 16/20 Carbolite. (Fluid: corn syrup.) Field Conductivity Results A client in South Texas analyzed production-decline data to estimate fracture conductivity from three fractures in the same well. The first was done on a fracture containing 20/40-mesh Interprop 1. The fracture conductivity was 1550 md-ft. This fracture produced excessive proppant, so a patch of resin-coated Interprop 1 was pumped. The production decline indicated a fracture conductivity of 860 md-ft with the curable RCP patch. The upper zone of this well was fractured using Interprop 1 containing J501. The production decline indicated a fracture conductivity of 1500 md-ft. 2.6 PropNET Lifetime The PropNET materials are made of glass. Glass is a meta-stable phase and can dissolve in water depending on temperature, time, composition of the glass, pH value and dissolved minerals in the water. The process occurs more quickly at high temperature, at acidic- or basic-pH values and in water without dissolved minerals. The dissolution process is known to begin at the surface and progress inward. It is generally a linear function of time (unless a passivating surface layer forms), but an exponential function of temperature.



DOWELL CONFIDENTIAL



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May 1998



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PropNET Technology



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Dowell



During the development of the PropNET additives, the diameter of the fibers was found to be important in determining proppant-pack stability. If the glass fibers dissolve over time, their effective diameter and the pack stability will decrease. Concerning the fracture, several factors are important. First, the time that the PropNET additive is in contact with the fracturing fluid is too short to have any effect (1 to 2 days) at less than 300°F (149°C); therefore, the water of interest is the formation water. In most fractured sandstone formations this water is silica saturated, has a pH value of 5.5 to 8, and has other dissolved species such as calcium that slow the dissolution process. Finally, as time passes after the fracture treatment, the well depletes, requiring less pack stability. Aging experiments were performed with silica-saturated water flowing through proppant packs containing the PropNET additive at 350°F (177°C), 300°F (149°C) and 250°F (121°C). The tests were run for 3 months, and at various times, samples were removed and tested for pack resistance to flow in the tube geometry (Appendix A). J500 followed normal dissolution behavior and the proppant-pack strength decreased linearly with exposure time. Fig. 6 is a result of these experiments. Percent of initial pack strength is plotted versus time for various BHSTs.



J500 - Pack Strength after Dynamic Ageing



Pack Strength, % Initial



100 90 80 50°C [122°F] 70°C [158°F] 90°C [194°F] 110°C [230°F]



70 60 50 40 0



2



4



6



8



10



Time, Years



Fig. 6. Predicted proppant-pack strength with aging time for J500. J501 does not follow normal dissolution behavior. The proppant packs containing J501 lost about 30% of the pack strength in two weeks at 350°F (177°C). After that, there was no further decrease. This behavior may indicate that either an equilibrium was reached, a protective layer formed on the surface or some other phenomenon. DOWELL CONFIDENTIAL



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Dowell



PropNET Technology



Section 700.9 May 1998 Page 21 of 32



The sand packs containing J501 showed much better pack strength retention than packs containing J500 at all times. J501 is expected to be more durable than J500 and have a higher use temperature. There is always risk in extrapolating the data at 350°F (177°C) to lower temperatures and longer times. Dissolution rate normally doubles for every 10°C increase in temperature. At 300°F (149°C), J501/proppant-pack stability should be sufficient for up to two years (assume 50% of the original stability). Extrapolation of stability to 10 years at lower temperatures is not recommended because of the limited time period of the laboratory aging tests (3 months). The first well treated in May 1994 with a reservoir temperature of 275°F (135°C) has been sand free. A dry gas well with a reservoir temperature of 355°F (179°C) was treated in February 1996 and has been sand free. 2.7 Stability in Acids J500 and J501 were tested for acid stability. Samples were tested for 24 hr at 175°F (79°C) and 1000 psi (6.9 mPa) (autoclave pressure), and 6 hr at 300°F (149°C) and 5000 psi (34.5 mPa). Samples were exposed to 15% HCl, 28% HCl, and NAS (NonAcid Solvent) fluids. Weight change was measured after exposure. J500 was strongly attacked by the concentrated HCl. The J500 lost approximately 30% of its mass during the tests. The NAS had little effect on J500, causing a small weight gain of 5%. The J501 was hardly affected by either the concentrated HCl or the NAS. Slight weight gains approximating 4% were seen after exposure to the fluids. Based on these results, J500 should not be used if the well will be treated with HCl in the future. J501 should be resistant to HCl exposure. Both PropNET additives should be stable to NAS exposure. Neither PropNET additive will survive exposure to treatment fluids containing HF. 2.8 Effect on Proppant Settling Adding the PropNET additive to the proppant slurry has the added benefit of reducing proppant settling. This can be seen in the laboratory by pouring slurries into graduated cylinders and observing the height of the proppant pack as a function of time. Fig. 7a and Fig. 7b show the height (volume) during settling of 20/40-mesh sand and 16/20-mesh Carbolite in WF* 150 at room temperature.



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FRACTURING ENGINEERING MANUAL



May 1998



Schlumberger



PropNET Technology



Page 22 of 32



Dowell



240 220 2% PropNET I J500



PACK VOLUME (mL)



200 180 160



1% PropNET I J500



140 120



NO PropNET additive



100 80 60 40 FLUID: UNCROSSLINKED 50 LB./1000 GAL. GUAR INITIAL PROPPANT CONCENTRATION: 8.3 PPA



20 0 0



50



100



150



200



250



300



350



TIME (min)



Fig. 7a. Proppant settling in WF150 fluid.



200



PACK VOLUME (mL)



2% PropNET I J500 150



1% PropNET I J500 NO PropNET additive



100



50 FLUID: 50 LB./1000 GAL. GUAR SOL'N. INITIAL PROPPANT CONCENTRATION: 8.3 PPA 0 0



100



200



300



TIME (min)



Fig. 7b. Proppant settling in WF150 fluid.



DOWELL CONFIDENTIAL



400



Section 700.9



FRACTURING ENGINEERING MANUAL Schlumberger



PropNET Technology



Dowell



May 1998 Page 23 of 32



Similar behavior is also seen in dynamic settling conditions. A slurry of 20/40-mesh sand was made with WF175 at room temperature, both with and without 1.5% J501. The slurry was placed in a transparent vessel with a cup rotating at 45 rpm in the center. The annular gap between the rotor and vessel was 0.16-in. (0.4 cm), giving a shear rate of around 65 sec-1 in the annular gap. The amount of free liquid was monitored as a function of time (Fig. 8). The addition of J501 to the slurry significantly reduces the rate of proppant settling: this is clear based on the amount of free liquid.



7



Sand



6



Sand + J501



5



4



3



2



1



0 0



20



40



60



80



100



120



Time (min)



Fig. 8. The effect of J501 on proppant settling in WF175 fluid under dynamic conditions. The PropNET additive slows the settling of the proppant and decreases the settled pack volume: this is clear from the settling curves. This reduced settling, under both static and dynamic conditions, should also occur in the fracture. Less settling of the proppant is expected when the PropNET additive is used. 2.9 Fiber Breakage During Treatments There have been concerns about the possibility of fiber breakage during mixing and pumping operations even though yard tests have not supported this. A fracturing treatment was performed on a North Sea well with J501 being added at a concentration of 1.5% to a fully curable resin-coated proppant. The last proppant stage was under-displaced and allowed to cure in the wellbore. The resin-coated proppant containing the J501 was then drilled out. The material (shown in Fig. 9) was circulated to a rig sand separator during the drilling operation. The fibers shown DOWELL CONFIDENTIAL



Section 700.9 May 1998 Page 24 of 32



FRACTURING ENGINEERING MANUAL



PropNET Technology



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Dowell



in Fig. 9 appear to be intact, the bundles measure between 0.47 and 0.98 in. (12 to 25 mm).



Fig. 9. Resin-coated proppant containing PropNET fibers after pumping and removal from a well. Fig. 10 shows fibers after cleaning to remove oil. The mass was sieved to determine if small fiber pieces were present. The majority of the fibers were approximately 0.47-in. (12 mm) long. A few fibers were approximately 0.24-in. (6 mm) long. No smaller fibers were found, indicating that no significant breakage of the J501 fibers occurred during fracturing and wellbore operations.



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Dowell



Section 700.9 May 1998 Page 25 of 32



Fig. 10. PropNET fibers after pumping, removal from a well and cleaning to remove oil. 2.10 Case Histories



South Texas Over 140 successful fracturing treatments using the PropNET additives have been performed in southern Texas. This case history reviews typical flowback and polymer cleanup out of one fracture. The well has two sandstone zones separated by a 15-ft (4.6 m) shale zone. The gross height is 100 ft (30.5 m). The net height is 25 ft (7.6 m). The depth is 8800 ft (2682 m). The average permeability of the producing zones is 0.8 md. A 28-ft (8.5-m) section and a 8-ft (2.4-m) section were perforated at 4 spf. The total number of perforations is 146. One large fracture with 226,000 lbm (102,514 kg) of 20/40-mesh Interprop 1, and 1730 bbl (275 m3) of borate-crosslinked guar fluid was pumped. J501 was added to the last 15% (vol) of the proppant. The flowback history is shown in Fig. 11. Flowback began as soon as the treating equipment was disconnected (30 min). The initial flowback rate was 500 B/D (79.5 m3/D) and increased to 1000 B/D (13.7 B/D/perforation). Gas broke through after 6 hours and the water rate decreased. The total proppant flowed back was 125 lbm (56.7 kg). This was 0.05% of the total proppant placed in the fracture. Normal experience with the PropNET additive in southern Texas is 50 to 350 lbm (23 to 159 kg) of proppant are produced during cleanup. Most proppant is produced in the DOWELL CONFIDENTIAL



Section 700.9



FRACTURING ENGINEERING MANUAL



May 1998



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PropNET Technology



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Dowell



two-phase flow time-frame when gas has broken through and before the water rate decreases significantly. The gas rate reached 10.6 MMcf/D for this well. The gas was flowed to sales the next morning, 12 hr after gas broke through. Total flowback time was four days. SOUTH TEXAS WELL, 15% PropNET J501 TAIL-IN 140



120 1000 100



80 100



PROPCUM WATER GAS



60



10



40



1



10



CUMLATIVE PROPPANT (LBS.)



WATER & GAS RATE (BBL/D, MCF/D)



10000



20 100



TIME (HOURS)



Fig. 11. South Texas well, 15% J501 tail-in. The rate of fluid returned and guar polymer concentration in the fluid were evaluated from this fracture (well A) and an offset well (well B). The offset well had two fractures. The top zone was fractured using J501 in the last 15% (tail-in) of the total proppant volume. The lower zone was fractured using curable resin-coated proppant in the last 23% (tail-in) of the total proppant volume. Fluid flowback from the three fractures is shown in Fig. 12. The two fractures containing J501 have much higher initial flowback fluid rates and earlier gas breakthrough than the fracture containing curable resin-coated proppant. The client’s experience was that fractures containing curable resin-coated proppant could not be flowed back at rates faster than 250 B/D without excessive proppant production. All three fractures returned fluid at about the same rate after gas breakthrough.



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Section 700.9



FRACTURING ENGINEERING MANUAL Schlumberger



May 1998



PropNET Technology



Dowell



Page 27 of 32



FLUID RETURNS SOUTH TEXAS OFFSET WELLS



CUMLATIVE FLUID RETURNED (BBLS)



450 400



WELL B UPPER (PROPNET)



350 300



WELL A (PROPNET) GAS



250 200



GAS 150



WELL B LOWER (RCP)



100 50 0 0



10



20



30



40



50



60



70



FLOWBACK TIME (hours)



Fig. 12. Fluid returns, South Texas offset wells. Samples of the flowback fluid were taken at one-hour intervals during the flowback. The samples were analyzed for guar concentration using a chemical tagging technique and UV/visible spectroscopy. The polymer concentration in the flowback fluid for well A (PropNET additive) and the lower zone of well B (curable RCP) were constant for the first two days. The polymer concentration in the flowback fluid of the upper zone of well B steadily decreased over the first two days. Based on the guar concentration in the flowback fluid and the rate of fluid return, the rate of polymer return can be calculated. The fraction of polymer pumped into the fracture that was returned is shown in Fig. 13. The two fractures containing the PropNET additive had rapid early polymer return rates, while the fracture containing curable RCP returned polymer gradually. This is a function of the fluid flowback rate. The two fractures containing the PropNET additive returned a higher fraction of the polymer in the 50 to 60 hour period; however, the fracture containing curable RCP may have returned the same amount of polymer after longer flowback times. Polymer return analysis from other fractures containing the PropNET additive show as much as 50% of the polymer returned in two days. This case history shows that the PropNET additives can be used as a tail-in to control proppant flowback. The use of the PropNET additive allows faster flowback rates than are commonly possible with curable resin-coated proppants, earlier gas breakthrough and earlier gas to the sales line. In many cases, shorter flowback time is observed, lowering cleanup costs. The PropNET additive allows for flexibility in flowback rate, to maximize the polymer cleanup. DOWELL CONFIDENTIAL



Section 700.9



FRACTURING ENGINEERING MANUAL



May 1998



Schlumberger



PropNET Technology



Page 28 of 32



Dowell



POLYMER RETURNS OFFSET WELLS 30



PERCENT POLM. RETURNED



WELL A ( PROPNET) 25



WELL B UPPER ( PROPNET) 20



GAS



15



GAS



WELL B LOWER (RCP) 10



5



0 0



10



20



30



40



50



60



70



FLOWBACK TIME (hours)



Fig. 13. Polymer returns, offset wells. Indiana Several low-temperature gas wells were fractured in the New Albany shale of southern Indiana. In all cases, multiple fracturing treatments were performed on a single well. No treatment contained more than 25,000 lbm of 20/40-mesh sand, and J501 was added to the last 50% of the proppant in most jobs. Previously, these types of wells were fractured using curable resin-coated proppant to control proppant flowback. This required expensive activator to be added to the fluid. The wells were shut-in overnight to allow the resin-coated proppant to cure. The packer was then moved, the cured resin-coated proppant in the wellbore was drilled out, and the next fracture was performed. The total time to fracture four zones in a well was 4 to 5 days. Wells containing J501 were flowed back within 10 min after the end of the job. The wells were flowed for 30 min. Very little proppant (approximately 27 lbm) was flowed back. No drilling or clean-out was required, and the packer could be moved soon after flowback. All four zones could be fractured in a total elapsed time of only 8 hr. By using the PropNET additive, cost savings included reduced job costs (no activator), and reduced rig time (approximately $1000 to $1400 USD per day).



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Dowell



Section 700.9 May 1998 Page 29 of 32



3 PropNET References US Patents



5,330,005, 5,439,055, and 5,501,275



SPE 30495



Howard, P. R. et al.: “Fiber/Proppant Mixtures Control Proppant Flowback in South Texas.”



SPE 31093



Romero, J. and Féraud, J. P.: “Stability of Proppant Packs Reinforced with Fiber for Proppant Flowback Control”.



SPE 35326



Prado-Velarde, E. et al.: “Proppant Flowback Control in the Burgos Basin.”



SPE 36468



Anderson, A. J. et al.: “Production Enhancement Through Aggressive Flowback Procedures in the Codell Formation.”



SPE Production and Facilities P271, November 1995, Card, R. J., et al.: “A Novel Technology to Control Proppant Back Production.”



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4 Appendix A - Flow Test Apparatus 4.1 Fracture Geometry The fracture geometry flow test apparatus is shown in Fig. 14. The slurry is pumped between two stone slabs and against a screen to form a pack. The screen is removed, closure stress is applied, and water (1 cp) is pumped through the cell to approximate production along the fracture. The flowing water drawdown (psi per linear foot of fracture) at which the pack flows out from between the stone faces is defined as the failure point. 4.2 Perforation Geometry The perforation geometry flow test apparatus is shown in Fig. 15. The slurry containing proppant and the PropNET additive is pumped through a perforation (normally 0.5-in. diameter, but can be varied up to 1-in.) and fills a fracture. The fracture is 4-in. high, 0.25-in. long and the width can be varied from 0.25-in. to 2.0-in. In the fracture, the excess fluid is allowed to leakoff via a screen at the exit of the cell, and a pack is formed. Once the pack has formed, water is flowed back through the fracture and out the perforation. Again the pressure drop and flow rate when the pack fails and flows out of the perforation are recorded. In this test, flowrate appears to be the key variable. Pressure drop is more variable due to the flow patterns around the perforation, and the shape of the arch at the perforation. 4.3 Tube Geometry The tube geometry flow test apparatus is shown in Fig. 16. The WF130 slurry containing proppant and the PropNET additive was pumped into the tube, and a pack was formed against a screen placed at the exit. The screen was removed and a washer was placed at the exit. The washer size could be changed.



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152



Cell



mm eter



diam



Proppant Pack



Flow



100 mm long



FRACTURE GEOMETRY CELL



Cell



Rock Face Proppant Pack



Closure Stress Fig. 14. Fracture geometry test apparatus.



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FRACTURE & PERFORATION NO CLOSURE F L U I D



PROPPANT PACK



PERFORATION 1/2” to 1”



F L O W FRACTURE



Fig. 15. Perforation geometry test apparatus.



FLUID FLOW



TUBE GEOMETRY



PROPPANT PACK WASHER Fig. 16. Tube geometry test apparatus.



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PropNET Flowback Information Supplement



Section 700.9 May 1998 Page 1 of 5



PropNET∗ FLOWBACK INFORMATION SUPPLEMENT 1 Wellbore Cleanup..................................................................................................................... 1 2 Flowback, Swabbing................................................................................................................ 1 3 Shut-in, Clean-up, and Production Rates .............................................................................. 2 4 Appendix................................................................................................................................... 4 FIGURES Fig. 1. Maximum swab-cable speed vs casing ID and number of perforations............................ 4 TABLES Table 1. Maximum Worldwide PropNET Flowback and Production Rates .................................. 5



1 Wellbore Cleanup Prior to swabbing or flowing a well to cleanup, removal of the underdisplaced slurry volume is recommended from the perforated wellbore area. Laboratory and field investigations show significant tendency for fibres to separate from the sand/liquid slurry as formation fluid or gas percolates through at low rate. The phenomenon is similar to separation of multi-sized particles with vibration or agitation. This may potentially result in a concentrated fibrous “mat or clump” which can contribute to plugging of surface chokes, during the cleanup phase. In the event excess “overhole” or “sump” is available, the slurry may be allowed to settle below the perforations during the gel-break process. If this is not practical, removal of the excess slurry and residual fibre from the tubing or casing may be accomplished either through high initial flowback rates (sufficient to move and lift slurry), or circulation of liquid or foam through coiled tubing. The latter is best completed prior to initiating swabbing or flowback. The coiled tubing unit is also capable of eliminating any potential proppant slurry bridges within the pipe. Bailing of sand bridges inside pipe is not recommended due to potential pressure differentials that can exist across the bridge.



∗



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2 Flowback, Swabbing During flowback a collection of fibres, similar to proppant, can plug a small choke. The use of a flowback manifold containing two parallel chokes is recommended. A plugged choke may then be removed and cleaned while flowback continues. Ensure the initial wellbore volume of returned fluid is not diverted directly into a disposal well. Initial wellbore/formation fluids should first be processed through a separation screen as noted in HSE section above, or a 15 mesh bag-filtration unit, where residual fibres can be separated from the fluid. If PropNET fibre is left in the rig/return tank, the material will begin to separate from the fluid, making the fluid/tank cleaning process more cumbersome. PropNET flowback recommendations are based on maximum comingled fluid/water rates. These must be measured during the swab/flowback period. Routine strapping of the fluid-returns tank is an adequate method to determine the liquid return rate. Foamfrac treatments present a unique situation since the water rate is not known during the initial period when unbroken foam flows back. A five centimeter diameter (2 in.) magnetic flowmeter and densitometer installed in the flowback line is recommended to estimate water rate following foamfracs. Also, a defoamer such as M45 may be added to the flowback tank in order to efficiently gauge fluid level.



3 Shut-in, Clean-up, and Production Rates Very short shut in times are needed for PropNET materials to control the proppant flowback (closure on proppant). Field experiences indicate that wells can be flowed back as quickly as 15 minutes following the end of pumping. Suggested initial flowback rates should not exceed the maximum flowback rate calculated below. Based on field experience, flowback stage recommendations are as follows: • Ensure fluid viscosity is broken (i.e. water viscosity) •



Initial rate - 500 bpd or Qmax (whichever is lower) to bottoms up



•



Adjust to ½ the ultimate maximum rate, then ¾, then full max. rate (each step for 2-4 hrs) (This sequence may be revised for intentional “molehole” applications for high rate multiphase flow. See the “molehole” (i.e. infinite conductivity channel discussion in the FEM, Section 7.9)



•



Keep initial choke adjustments to < 2/64ths at a time.



As swabbing can potentially cause a flowrate in excess of Qmax, maximum swabline pull rates are also given in Fig. 1 of the Appendix. Dowell recommends initial cleanup and production rates not to exceed 30 bbl/day per contributing (communicating with fracture) perforation (Qperf) for sand and 20 bbl/day per perforation for ceramic proppants. The maximum initial flowback rate Qmax can be calculated using the equation below. Divide the Qperf by the downhole fluid DOWELL CONFIDENTIAL



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May 1998 Page 3 of 5



viscosity µ2/3 for oil wells or when unbroken fracturing fluid is flowing back. The number of perforations (Np) is divided by 2 because we assume only half the perforations communicate with the fracture. A correction for two phase water/gas flow has already been added to this calculation.



(



)(



)



Qmax = Q pert / µ 2/ 3 N p / 2 Where:: Qmax



= maximum flowback rate (bbl/day)



Np



= number of perforations in the fracture zone



µ



= viscosity of fluid at bottom hole conditions, centipoise. (Broken fracture fluid usually has a viscosity of 1 - 10 cp at BHST) (Emulsified fluids will exhibit higher equivalent viscosities)



Qperf



= maximum flowback rate per perforation (bbl/day/perforation) 30 bbl/day (4.8 m3/day)/perforation for sand 20 bbl/day (3.2 m3/day)/perforation for ceramic proppants



Ultimate flowback and production rates can vary significantly depending on the well, the nature of the produced fluids and reservoir conditions. The maximum rates for any given group of wells must be determined on a case by case basis. Qmax is typically used as a starting point for the maximum rate, then rates are increased until proppant is produced, or until the maximum proppant-free flowrate of the well is achieved within production string limitations. A summary of maximum proppant-free production rates from various areas around the world are given in Table 1 of the Appendix.



Expected Events During High-rate Gas Flowback: •



Appearance of fiber anytime during bottoms up (dispersed or solid clumps)



•



Sand and fiber strung out in wellbore, concentrated near bottomhole



•



Probable sand production during/after bottoms up, typically subsides as well cleans up



•



Sand produced after each rate change, typically subsides during constant rate



•



Gas break-through at 18-20% of clean fluid pumped



•



30-50% of load water returned in a few days.



Reference: PropNET Information Summary, S. D. Bittner (CDN), January 17, 1997



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4 Appendix MAXIMUM SWAB-CABLE SPEED VS CASING ID AND NUMBER OF PERFORATIONS



Swab Cable Speed (ft/min)



10000



1000



100



10



1 1



2



3



4



5



6



7



8



9



10



Casing ID (in.)



5 Perforations 10 Perforations 25 Perforations 50 Perforations



ASSUMPTIONS:



1 1. Maximum Allowable Production Rate: 30 bbl/day/perforation. 2. All perforations produce at equal rates in response to swabbing. 3. All perforations produce fluid instantaneously in response to swabbing.



1 PropNET Manual Addition



Fig. 1. Maximum swab-cable speed vs casing ID and number of perforations.



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Section 700.9 May 1998 Page 5 of 5



Table 1. Maximum Worldwide PropNET Flowback and Production Rates



Flowback Rates Area



Oil/Gas



WTX



Oil



Overall Rate (bbl/d) 2160



BCA



Oil



2500



50+



SET



Gas



5760



96



STX



Gas



3600



50



Area



Oil/Gas



Overall Rate



Rate/perf



WTX



Oil



200 bbl/d



10 bbl/d



OUK*



Oil



9600 bbl/d



24 bbl/d



STX



Gas (wet)



5900 mcf/d



92 mcf/d



YMX



Gas (wet)



12000 mcf/d



65 mcf/d



OUK*



Gas (dry)



35000 mcf/d



580 mcf/d



Rate/perf (bbl/d) 114



Production Rates



(* PropNET w/RCP)



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HyPerSTIM Service



Section 800 May 1998 Page 1 of 76



HyPerSTIM SERVICE 1 Introduction .............................................................................................................................. 4 1.1 Objectives ............................................................................................................................ 4 1.2 Applications.......................................................................................................................... 5 1.3 Limitations of Application ..................................................................................................... 6 2 Design ....................................................................................................................................... 6 2.1 Candidate Selection ............................................................................................................. 7 2.2 Characterization of Formation Mechanical Properties ......................................................... 9 2.3 Design Basis ...................................................................................................................... 10 2.4 Fluid Selection ................................................................................................................... 15 2.4.1 Fluid-Loss Control .................................................................................................... 16 2.4.1.1 Pressure Effects............................................................................................. 18 2.4.1.2 Temperature Effects ...................................................................................... 19 2.4.1.3 Effects of Fluid Viscosity and Polymer........................................................... 20 2.4.1.4 Effects of Fluid-Loss Additives....................................................................... 21 2.4.1.5 Fluid Selection and Fluid-Loss Control .......................................................... 21 2.4.2 The DataFRAC Service Application.......................................................................... 21 2.5 Proppant Selection and Fracture Conductivity................................................................... 22 2.5.1 Embedment .............................................................................................................. 23 2.5.1.1 Spalling .......................................................................................................... 25 2.5.1.2 Impact on Permeability .................................................................................. 26 2.5.2 Non-Darcy Flow ........................................................................................................ 27 2.5.2.1 Determination of the Inertial Flow Coefficient ................................................ 28 2.5.2.2 Non-Darcy Flow Correction of Dimensionless Fracture Conductivity ............ 32 2.5.2.3 Proppant Selection Using Manual Calculation ............................................... 33 2.5.2.4 Computer-Aided Proppant Selection ............................................................. 35 2.5.2.5 Proppant Selection Using the FracCADE Software ....................................... 37 2.5.2.6 Proppant Selection Summary ........................................................................ 37 2.5.3 Formation Sand and Fines ....................................................................................... 37 DOWELL CONFIDENTIAL



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2.5.3.1 Control of Formation Fines and Sand ............................................................40 2.5.4 Proppant Flowback Control.......................................................................................40 2.6 FracCADE Software ...........................................................................................................44 2.6.1 FracNPV and QUICK Modules..................................................................................44 2.6.2 The FORECAST Module...........................................................................................47 2.6.3 The PLACEMENT II Simulator ..................................................................................49 3 Execution ................................................................................................................................54 3.1 Batch-Mix Operations .........................................................................................................54 3.2 Continuous-Mix Operations ................................................................................................55 4 Evaluation ...............................................................................................................................55 4.1 Prats’ Correlation................................................................................................................56 4.2 Modified McGuire-Sikora Correlation .................................................................................56 5 Fluid-Loss Data ......................................................................................................................64 5.1 WF120 (J164) Containing 25 lbm J478/1000 gal and 25 lbm J418/1000 gal BHST=150°F (66°C), Pressure=1000 psi ..........................................................................64 5.2 WF160 (J164) Without Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................65 5.3 WF160 (J164) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................66 5.4 WF110 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure- 1000 psi .............................................................................................................67 5.5 WF120 (J424) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................68 5.6 WF130 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................69 5.7 WF140 (J424) Containing 50lbm J238/1000 gal  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................70 5.8 WF160 (J424) Containing Various Fluid-Loss Additives  BHST=150°F (66°C), Pressure-1000 psi ..............................................................................................................71 5.9 YF140 (J424)  BHST=150°F (66°C), Pressure-1000 psi ................................................72 5.10 YF140 (J424)  BHST=150°F (66°C), Pressure-1000 psi ..............................................73 5.11 YF140 (J424)  BHST=175°F (79°C), Pressure-1000 psi ..............................................74 DOWELL CONFIDENTIAL



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5.12 YF140HTD (J424)  BHST=200°F (93°C), Pressure-1000 psi ...................................... 75 5.13 YF140HTD (J424)  BHST=250°F (121°C), Pressure-1000 psi .................................... 76 FIGURES Fig. 1. Fig. 2. Fig. 3. Fig. 4. Fig. 5. Fig. 6. Fig. 7.



Production rate sensitivity to skin...................................................................................... 8 IPR curve sensitivity to skin. ............................................................................................. 8 The effect on shifting an 80% damage collar. ................................................................. 11 Productivity-increase curves. .......................................................................................... 12 Effective wellbore radius for pseudo-radial flow.............................................................. 14 Fluid-loss data for YF140................................................................................................ 17 Pressure gradient through a sand pack versus gas flow rate, darcy and non-darcy flow................................................................................................................. 27 Fig. 8. Total pressure drawdown versus transit time, sanding prediction. ................................. 39 Fig. 9. Curable resin-coated proppant compressive strength required to prevent flowback. .... 44 Fig. 10. Proppant Editor. ............................................................................................................ 45 Fig. 11. FracNPV Input. ............................................................................................................. 45 Fig. 12. Equivalent wellbore radius and pseudo-skin................................................................. 47 Fig. 13. PRODUCTION FORECAST input................................................................................. 47 Fig. 14. Production simulation, non-darcy flow. ......................................................................... 49 Fig. 15. ROCK input. .................................................................................................................. 50 Fig. 16. ZONES — layer data input........................................................................................... 51 Fig. 17. PLACEMENT SIMULATOR — conventional design, 20/40-mesh sand, 1400 gal pad. ............................................................................................................... 57 Fig. 18. PLACEMENT OUTPUT — conventional design, 20/40-mesh sand. ............................ 57 Fig. 19. PLACEMENT SIMULATOR — P3D tip-screenout design, 20/40-mesh sand, 1600 gal pad. ............................................................................................................... 58 Fig. 20. PLACEMENT OUTPUT — P3D tip-screenout design, 20/40-mesh sand.................... 58 Fig. 21. PLACEMENT SIMULATOR — conventional design, 12/20-mesh sand, 1800 gal pad. ............................................................................................................... 59 Fig. 22. PLACEMENT OUTPUT — conventional design, 12/20- mesh sand. .......................... 59 Fig. 23. PLACEMENT SIMULATOR — P3D tip-screenout design, 12/20-mesh sand, 3500 gal pad. .................................................................................................................. 60 Fig. 24. PLACEMENT OUTPUT — P3D tip-screenout design, 12/20-mesh sand.................... 60 Fig. 25. Stage front propogation. ............................................................................................... 61 Fig. 26. Fracture height profile ................................................................................................... 61 Fig. 27. Wellbore fracture width profile. ..................................................................................... 62 Fig. 28. Fracture height growth history. ..................................................................................... 62 Fig. 29. Fracturing (net) pressure profile.................................................................................... 63 TABLES Table 1. Water Viscosity at Temperature................................................................................... 20 Table 2. Dry Proppant Pack Intertial Coefficient Factors ........................................................... 31 Table 3. Proppant Selection With Embedment and Non-Darcy Flow ........................................ 35



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1 Introduction Fracturing technology has traditionally been applied to low-permeability formations to stimulate production. More recently, fracturing has been successfully applied to high-permeability formations (from 10 md to more than 500 md). The practical application and rewards of fracturing high-permeability formations include damage by-pass and stimulation through creation of a large effective wellbore radius. The fracture treatments are designed to overcome limitations of conventional matrix treatments. Matrix treatments often fail to provide sustained production response because of factors such as layered or heterogeneous permeability, acid sensitivity and formation deconsolidation. An alternate means of providing effective wellbore communication and stimulated response is required. Because of these factors, the HyPerSTIM* design and execution technology was developed. The difficulty of achieving effective fractures in high-permeability formations must be considered. In addition to achieving effective fluid-loss control, the major considerations include generation of adequate fracture-conductivity contrast (considering embedment and the impact of non-darcy flow), characterization of soft formations and post-treatment control of proppant mobility. 1.1 Objectives The HyPerSTIM Service is the fracturing design, execution and evaluation service dedicated to fracturing moderate - to high-permeability formations. The primary objectives of the HyPerSTIM Service include: • to extend fracturing services to exploit high-permeability reservoirs by providing an effective horizontal and vertical communication pathway, a pathway possibly blocked by difficult-to-remove formation damage •



to improve the high-rate well productivity of “unstable” formations where fines mobility resulting from large pressure drawdowns associated with radial matrix flows in low-cohesion sands is a problem



•



to complement sand-control services for unconsolidated low-cohesion sands



•



to overcome the limitations of matrix acidizing and other solvent treatments when high-permeability formations exhibit unacceptable response, or where damage is too deep and extensive to remove (cost-effectively) using matrix injection techniques



•



to provide a means and design methodology to improve all conductivity-limited fracture treatments.



1.2 Applications



Damage Bypass *



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Section 800 May 1998 Page 5 of 76



Fracturing (versus large matrix treatments) can be a cost-effective means of achieving zero- or negative-skin responses. The limiting factors are fracture conductivity and the ability to place proppant because of high fluid-leakoff rate. Damage mechanisms can include, but are not limited to: • cement or mud filtrate damage or both •



inadequate number of perforations or plugged perforations



•



scale deposition due to pressure changes near the wellbore



•



fines mobility caused by high matrix flow velocities



•



low-cohesion formation collapse due to large pressure drawdown



•



non-darcy flow effects and resulting pseudo-skin at high rates.



Connecting Reservoir Permeability Laminated reservoirs with multiple vertical lithology and permeability variations can be interconnected through a high-conductivity vertical fracture to increment reserves. Matrix diversion may be difficult to achieve or perforating multiple zones may prove costly. Horizontal wells drilled in large high-permeability zones may have similar application if additional smaller laminae are present or if limited vertical permeability exists within the drilled zone.



Mobility Control of Fines and Sand Low-cohesion unconsolidated sands are subject to movement due to the viscous drag imparted by the velocity of the flowing reservoir fluid. The erosion that takes place results from exceeding the apparent cohesion stress. In addition, marginal low-cohesion-strength formations may be destabilized and subject to fines mobility. Pore collapse, local shear or tensile failure can occur from excessive differential stress caused by large pressure gradients. Fracture stimulation increases the effective wellbore radius and flow area and enables the production rate of high permeability wells to be maintained at higher bottomhole flowing pressures, reducing the overall effective stress applied on the rock matrix.



Stimulation Moderate-permeability oil reservoirs (10 to 50 md) can achieve stimulation ratios greater than two from deeper fracture penetration (100 to 300 ft) when the CleanFRAC∗ Service technology, high-permeability proppants and fracture widening tip-screenout techniques are used. High-permeability wells will generally be conductivity limited, with stimulation ratios typically in the 1.5 to 2.5 range. Large fracture widths also contribute to stimulation by reducing the flow velocity and nondarcy inertial effects for high-rate wells.



∗



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1.3 Limitations of Application Application of the HyPerSTIM Service is considered impractical or difficult in the following situations. • In very-high-permeability reservoirs where high-rate fracture fluid loss restricts proppant placement. Small-mesh proppant may be used in some cases with restricted propped fracture-length and width. • In reservoirs with very close gas/oil/water contacts and no fracture height-growth restriction. • In low-cohesion, low-compaction sands which behave inelastically (generally greater than 30% porosity). Application of the DataFRAC* Service may be limited. A fully packed fracture will be required, dictated primarily by gravelpacking criteria.



2 Design Problem definition is key in determining the application of fracturing and the HyPerSTIM Service for high-permeability wells. Conventional techniques such as pressure transient testing, laboratory core studies, production history evaluation, and application of NODAL* systems analysis, can be used to quantify problem areas and well potential. Nonmechanical, near-wellbore matrix damage can readily be obtained through simple transient testing. Mechanical, rate, and pressure dependent effects require more complex evaluation techniques. Additional information regarding well performance evaluation, and discussions regarding various skin behavior is provided in the Dowell Well Performance Manual. Examples to be aware of include • The determination of matrix non-darcy effects requires four-point rate and pressure evaluation to properly assess velocity effects on pressure loss. • Variable and deeply penetrating damage resulting from water flood alteration of permeability (scale & salts deposition, fines mobilization) can be difficult to determine. Core mineralogy and flow studies, combined with special transient analysis techniques are required. • Stress-dependent permeability requires a combination of pressure buildup and drawdown testing. • Matrix stability and prediction of sand movement under reservoir fluid flow and pressure reduction requires detailed study. Previous production practices and history will provide sufficient information for unconsolidated reservoirs. Marginal cases will be more difficult to determine. Rock mechanics testing for grain cohesion data and shear failure criteria may be required. Refer to Section 2.5.3.



*



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HyPerSTIM Service



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Section 800 May 1998 Page 7 of 76



2.1 Candidate Selection In conjunction with problem definition, the use of NODAL systems analysis is used to select a potential high-permeability candidate. The available software tools are the STAR∗ software, ZODIAC* software and Systems Analysis Model (SAM+) software for well test analysis, reservoir calibration/production prediction and NODAL analysis. Since high-permeability reservoirs will reach pseudo-steady-state flow in a relatively short time the applicable Darcy, Vogel/Darcy, or Jones equation should be used in the analysis of reservoir response. The SAM manual provides additional information. The time to reach pseudo-steady-state flow can be calculated using Eq. 1. t=



948 φ µ ct re2 k



(1)



Where:



t = time (hr) φ = porosity (fraction) µ = viscosity (cp) ct = compressibility (psi-1) re = drainage radius (ft) k = permeability (md). The SAM sensitivity analyses should take into account the following factors. 1.



Consider the existing well conditions to match production for various effective skin values. Rate sensitivity to skin will provide a confirmation of damage and an assessment of the production potential after stimulation. The fracture will be conductivity-limited for high-permeability wells, therefore short fractures and lower negative skin values (0 to -2) are probable. Longer fractures, with negative skin values approaching -4, are possible for moderate permeability wells (10 - 50 md). Fig. 1 illustrates production rate sensitivity to skin. Fig. 2 illustrates inflow performance relationship (IPR) curve sensitivity to skin. If effective total skin is known from transient tests, the completion effects on skin must be subtracted in order to determine the effective skin due to damage and rate effects alone.



2.



∗ +



Conduct sensitivity to producing and completion effects (that is, perforation type, shot size and density, partial penetration, gravel pack, tubing and pressure) to eliminate potential for misapplication of the fracture treatment. A near-zero skin may be possible by adjustment of the completion. If applicable, include the gravel-pack completion effects after the stimulation treatment. Consider the impact of well deviation and azimuth on postfracture productivity (Chapter 19 in Reservoir Stimulation) when making comparisons.



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Include the turbulent/non-darcy effects in radial matrix, gravel-pack and perforation flows for all gas wells (Jones et al correlations) when evaluating the impact of skin or the increase in effective wellbore radius. Very-high-rate oil wells may also provide non-darcy effects, although for the majority of cases this will not need to be considered.



Fig. 1. Production rate sensitivity to skin.



Fig. 2. IPR curve sensitivity to skin. DOWELL CONFIDENTIAL



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Section 800 May 1998 Page 9 of 76



2.2 Characterization of Formation Mechanical Properties The determination of static mechanical properties (Young's modulus and Poisson's ratio) from laboratory simulated in-situ conditions is recommended whenever possible for initial design estimates. Effective modulus calibration through the use of the DataFRAC Service is necessary to account for lithological variances and to enable accurate tip-screenout designs. Mechanical properties and acoustic wave velocities of sedimentary rock depend on the following. • absolute porosity (size and geometry) •



lithology (grain mineralogy and size)



•



cement mineralogy and degree



•



texture (compaction and grain orientation)



•



type of saturating fluid.



Unfortunately, useful correlations between field dynamic data versus laboratory static data have not been developed to enable direct use of sonic-derived properties.



Default Values Evaluation of numerous highly porous and permeable reservoir rock data indicates that the existing elastic modulus versus porosity correlations within the FracCADE* software provide acceptable Young's modulus approximations in the absence of specific data. The difficulty in using the default values when no specific data is available, lies in proper lithologic description of the formation. The majority of high permeability fracturing candidate sandstone reservoirs will fall into or lay between the following three available categories. • Quartz arenites (clean sand) — less than 10% total feldspars and clays, quartz rich, well cemented with quartz or carbonate. Porosity correlated elastic modulus ranges from 5.6 million psi at 10% to 2.6 million psi at 30%. •



Feldspathic/arkosic sandstones (dirty sand) — greater than 20% total feldspars and clays, clay may be the cementing material. Porosity correlated elastic modulus ranges from 3.5 million psi at 10% to 0.5 million psi at 30%.



•



Shales/siltstones (shale) — high clay content (greater than 30%), unconsolidated sands. Porosity correlated elastic modulus ranges from 1.3 million psi at 10% to 0.09 million psi at 30%.



For weakly consolidated, friable sandstones, the interpolated average between the dirty sand and shale/siltstone classification is suggested. For low-cohesion, unconsolidated sand the shale/siltstone correlation is suggested. If unsure of rock classification between clean sand or dirty, use the average of moduli specified for *



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each. A review of core analyses or petrographic and SEM/XRD studies will aid in properly classifying the rock mineralogy. Poisson's ratio correlation is related more to the lithology and cementing material. The value of Poisson's ratio, v, has a small impact on fracture width. Since the width varies inversely to (1-v2)0.2 to 0.25, the average default values will be acceptable for the majority of cases. The default value should not however, be used for stress estimation. 2.3 Design Basis For matrix treatments, a damage collar is removed or shifted away from the wellbore area as illustrated in Fig. 3. The productivity improvement ratio is calculated using Eq. 2. Practically, matrix treatments in sandstones can achieve a zero-skin effect. Q / Qo =



(1 / ko ) log(re / rw ) (1 / ko )log( rx / rw ) + (1 / kd ) log(rc / rx ) + (1 / ko ) log(re / rc )



Where all units are consistent units, and: Q = stimulated production rate Qo = original production rate ko= original undamaged reservoir permeability kd = permeability of the damaged zone rw = wellbore radius re = drainage radius rc = outer damage collar radius rx = radius of damage removed area, inner collar radius.



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Fig. 3. The effect on shifting an 80% damage collar. Assuming no completion effects, the minimum goal for the HyPerSTIM Service application is removal of the total skin effect due to damage mechanisms. Stimulation is possible with adequate fracture conductivity contrast. The folds of increase in productivity of a well under pseudo-steady-state flow conditions may be estimated using the correlations developed by Tinsely, McGuire-Sikora, RaymondBinder and others. As per the modified McGuire-Sikora chart, Fig. 4, the ratio of fractured production response to undamaged radial flow is a function of the fracture conductivity, and the fracture penetration expressed as a fraction of the drainage radius. In most cases, for high-permeability reservoirs where fracture penetration and conductivity ratio will be limited, the productivity index will be between 1.5 and 2.5.



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Fig. 4. Productivity-increase curves. For damaged wells, similar adjusted McGuire-Sikora charts or equations of Raymond and Binder may be used. The fractured productivity responses will obviously be higher when compared to the damaged well productivity. Additional discussion is provided in Reservoir Stimulation or SPE Monograph 12, Recent Advances in Hydraulic Fracturing. The equivalent wellbore concept proposed by Prats is the simplest to use for estimating the effect of a finite-capacity fracture in high-permeability wells. For fractured wells, the time to reach pseudo-radial flow (fractured case) can be estimated using Eq. 3, when the dimensionless time is approximately equal to two (greater than 1.6 for infinite-conductivity fractures or 2 to 5 for finite-conductivity fractures). For high permeability, the time will be in the order of hours or days. The higher rate produced during transient time can generally be neglected.



t=



3,788 φ µ c t x 2f t Dxf k



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Where: t = time (hr)



φ = porosity (fraction) µ = viscosity (cp) ct= total compressibility (psi-1) xf = fracture half length (ft) k = reservoir permeability (md) tDxf = dimensionless time (approximately two). During the pseudo-radial flow period, a fractured well behaves like an unfractured well with an effective wellbore radius being a function of dimensionless fracture conductivity. As the effective wellbore radius (rw′) increases, so does the production due to a larger negative pseudo-skin effect (Eq. 4). Fig. 5 indicates that the primary variables affecting rw′ and production are the reservoir permeability (k), fracture length (xf) and fracture conductivity (kfw) or dimensionless conductivity (CfD). S = − ln(rw′ / rw ), or rw′ = rw e − S



(4)



Where: S = skin effect (dimensionless) rw' = effective wellbore radius (in.) rw = wellbore radius (in.). A CfD of approximately 10 or greater indicates that production is a function of fracture length only and rw' = xf /2. For CfD values less than 10, production will be a function of fracture length and conductivity, and rw' will be a function of the dimensionless conductivity. The effective propped length is noticeably restricted for CfD values less than 1.6. At very low CfD values (200 [>93]



0.30



2.4.1.3 Effects of Fluid Viscosity and Polymer Without particulate fluid-loss control for high-permeability matrices, spurt will increase as viscosity decreases. With particulates, the spurt time decreases as the viscosity decreases. This is due to rapid transport of the solids to the rock fractureface surface, quickly establishing an effective filter cake. Additionally, the smaller polymer molecule structure may not impede the blockage of the larger critical porethroats by particulates to the same degree as larger polymer structures. The wall-building coefficient values are lowered with increasing polymer load as more polymer residue is available to bridge with the fluid-loss additive within the fixed time period of the test. For wall-building fluids, the polymer concentration will dominate the leakoff coefficient. A minimum of 20 lbm/1000 gal of guar or hydroxypropylguar (HPG) is required to provide adequate leakoff control when fluidloss additives are used. Studies have shown for equivalent polymer concentration, borate- and metal-crosslinked guar-derivative fluids have similar wall-building coefficient values, provided the metal-crosslinked systems are delayed and not shear-degraded prior to filtration. Shear-degraded systems have substantially higher leakoff values. Fluids containing low-residue hydroxyethylcellulose (HEC) polymers without fluidloss additives are assumed to exhibit viscosity-controlled leakoff behavior. The formation of very small microgels (nondispersed, partially-hydrated polymer) resulting from inadequate shear in mixing, often results in gradual polymer filtration and the formation of a filter cake. Additional shear and filtration (common in sandcontrol operations) results in a cleaner fluid with higher leakoff rate, approaching true viscosity control. Viscosity-controlled leakoff in low-permeability reservoirs ( 0.8 ⋅ 10 12 psi 2 b



Where: G = dynamic shear modulus (psi) cb = bulk compressibility (psi-1). Another approach uses total drawdown pressure (depletion included) versus compressional sonic transit time. Monitoring of produced debris for wells at various drawdown pressure is required. Fig. 8 illustrates an example that has been established using data from various fields. The position of the “risk” region is field dependent. The data, in absence of other specific data, may be used with caution as an indication of sanding risk.



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Fig. 8. Total pressure drawdown versus transit time, sanding prediction. •



•



•



*



Laboratory experimentation using a triaxially loaded core to determine the failure envelope (linear cohesion stress value and angle of internal friction) with varying pore pressure will provide the relationship between the effective stress, shear failure and critical pore pressure. Thick-walled hollow cylinder tests will aid in determining the critical pressure gradient at which sanding problems are initiated. The Schlumberger IMPACT* data processing system may be used for rock mechanics evaluation and to predict sanding tendencies. The data processing system uses shear and compressional wave transit times (derived from the Dipole Shear Sonic Imager), density, pore pressure, minimum in-situ stress, laboratory rock strength parameters, porosity and geochemical logs, and other data to forecast theoretical critical pressure and sanding tendencies. Theoretical modeling requires a mathematical formulation of the sand failure mechanism, often difficult to obtain. Validation with laboratory and field sand production data is essential. Without calibration, current theoretical tools are primarily for qualitative use.



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2.5.3.1 Control of Formation Fines and Sand Current sand-control technology involves the use of sized gravel and screens to limit sand movement and permeability reduction near the wellbore. High-conductivity fracturing offers one additional mechanism for marginal sand producers; reduction of pressure gradient and fluid velocity at the same producing rate through effective wellbore enlargement.



Low-Cohesion, Unconsolidated Reservoirs • Control is required through follow-up gravel packing (The STIMPAC Service). Average grain diameter of the gravel (proppant) should be six times the average grain diameter of the formation sand at the cumulative 50th percentile weight. This criteria should be considered for wells with a previous history of continuous sand production where the probability of disrupted sand aggregates and discretized particles near the wellbore exists. •



The gravel-pack design and gravel and screen selection criteria are provided in the Sand Control Engineering Handbook. Conventional sand-control hardware may be used for small slurry volumes when fracturing at low rates (less than 15 bbl/min) with the tools in place. For higher-rate treatments the use of a modified and hardened crossover assembly is recommended (see Section 2.5.4, Proppant Flowback Control).



•



Fracture proppant selection may be modified and grain size increased if laboratory core/proppant flow evaluations are available. Average grain size to 18 times the average grain diameter at the cumulative 50th percentile by weight has been shown to be effective due to formation grain agglomeration and lower pressure gradients.



Marginal Sand Producers, Friable-Consolidated Reservoirs • Determine the minimum effective stress level where sand production occurs. •



Conduct production rate sensitivity to generated fracture geometry with various proppants at maximum allowable drawdown (less safety factor). Compare to radial flow rate obtained for an undamaged matrix at equivalent differential pressure.



•



Select proppant using previously discussed methodologies.



2.5.4 Proppant Flowback Control Factors for determining excessive proppant flowback in high-permeability wells include combinations of the following. • Low closure stress — Low closure stress limits the normal force applied to the proppant grains. •



The proppant grain properties of sphericity, relative roughness and surface friction coefficient; — Angular proppants tend to bridge, causing them to DOWELL CONFIDENTIAL



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withstand higher drag forces prior to movement. Because of permeability loss, however, angular proppants are limited to low-stress environments. •



Grain size-distribution and packing — Similar sized particles provide higher permeability but are less likely to bridge.



•



Proppant density — Untrapped proppant grains of higher density are less likely to be mobilized by fluid moving through the fracture than lighter grains.



•



Proppant concentration in the fracture — Monolayers, or layers less than 3 grain diameter widths, are more likely to contain proppants. They do however, provide lower conductivity and higher relative embedment and non-darcy effects.



•



Effective drag forces acting on the proppant grains — High flow velocities create larger dynamic pressure and fluid momentum forces. Non-darcy flow increases the fluid drag and effective friction factor. These effects are magnified by perforating only a portion of the expected fracture height.



•



Effective flowing fluid viscosity — High-viscosity fluids or multiphase flow introduces large effective viscosity resulting in increased drag.



The above combined effects for proppant packs have not been fully investigated and modeled. Given the fracture requirements of the HyPerSTIM Service, two major techniques of proppant flowback control are available — mechanical isolation using the STIMPAC Service proppant exclusion system or the use of curable resin-coated proppant.



Proppant Exclusion Using Mechanical Devices Isolation packers, wire-wrapped screen hardware and modified crossover tools are used to conduct the fracture treatment through and enable control of severe proppant-flowback and fines production. The basic equipment list includes the following. • Model 18 sump packer — The Model 18 sump packer locates and supports the screen, blank pipe and Model 21 production packer. The Model 18 allows passage of debris into the rat hole. • • •



* +



Model 18 seal assembly — The Model 18 seal assembly allows communication through the Model 18 sump packer. Long-stroke PosiTest* packer — In deviated (greater than 60 degrees) wells where wireline setting is not possible, the PosiTest packer can be used. A screen or wire-wrapped perforated tubing — A screen or wire-wrapped perforated tubing sized for fracturing proppant may be used. A prepacked screen may be used as an alternate. Five to ten feet of overlap above and below the under-reamed casing window is recommended. A SUPER-SET+ screen handling table should be used to minimize screen damage.



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•



Blank pipe or spacer tubing — A blank pipe or spacer tubing is used below the Model 21 packer to allow for extended seal assembly and tubing movement compensation. A blank pipe or spacer tubing is also used below the safety shear collar for separation of the crossover assembly from screen. The length normally equals the screen length.



•



Safety shear collar; — The safety shear collar provides a means of releasing the Model 21 packer and circulating housing enabling retrieval from the well.



•



Crossover assembly — The crossover assembly allows for high-rate (greater than 50 bbl/min) slurry placement behind the screen with minimum erosion. Following placement, the port-isolation assembly is closed and the shift assembly retrieved using coiled tubing, allowing production communication through the screen.



•



Model 21 packer — The Model 21 packer is a retrievable production packer set hydraulically or on wireline. The differential pressure rating is 6000 psi at 210°F (99°C).



•



Model 21 seal assembly — The Model 21 seal assembly provides for tubing connection to packer. Connection is via a no-go locator, collet locator or snaplatch locator. A collet locator assembly is preferred for fracturing operations to ensure positive location and allow seal movement.



•



Coiled tubing fishing/shifting tools — These are overshot tools with circulation subs and knuckle joints. Following coiled tubing circulation of proppant debris above the fishing neck, the tools are used for shifting crossover assembly ports and for retrieval of the shift assembly.



The STIMPAC Proppant Exclusion System manual provides basic operation, procedures and parts information.



Curable Resin-Coated Proppants The use of curable phenolic resins with proppants, has long been recognized as a method for controlling proppant flowback. A tail-in treatment technique using curable resin-coated proppant for 10% to 20% of the total proppant pumped, is used in the majority of treatments. The technique has met with mixed results. Norman, et al conducted laboratory evaluations using curable resin-coated proppant to determine the strength required to prevent flowback. Fig. 9 may be used to approximate the required minimum compressive strength of a cured pack relative to the production rate through a 0.5 in. perforation. Refer to SPE 20640 for additional information. When curable resin-coated proppants are considered, design considerations should include the following. • The potential of premature proppant bridging at high proppant concentrations may preclude total coverage of perforations by the curable resin-coated proppant. This may result in proppant flowback from some intervals. Multi-layer DOWELL CONFIDENTIAL



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perforated intervals, vertical wellbores with greater than 20 ft of gross perforations and highly deviated (greater than 45°) wellbores are candidates for the use of curable resin-coated proppant throughout the slurry, as opposed to curable resin-coated proppant in just the tail-in slurry. •



Incompatibility with high-pH (greater than 10) borate-crosslinked fracture fluids. Curable resin-coated proppant reduces the pH value 1 to 1.5 units. The result is less available crosslinker and reduced fluid viscosity. Additional crosslinker (2 to 3 times) may be added to compensate. In the case of nondelayed systems, additional activator may be added.



•



Incompatibility with oxidizing breakers, Breaker J218, J475, or J479. The type of curable resin-coated proppant, weight percent of coating, free resin dust and proppant concentration will determine the threshold amount of ammonium persulphate required to effect a break. Once the threshold amount is exceeded, the required breaker will be proportional to polymer concentration. Two to ten times as much breaker may be required to overcome the neutralization effect of the resin.



•



Compressive and tensile strength of the curable resin-coated proppant is reduced with high pH values and oxidizing breaker concentration. A minimum compressive strength of 150 psi is recommended for high-rate wells to minimize potential flowback problems. When curing acceleration is required in crosslinked YF fluids, 3 to 5% (vol/vol) Isopropyl Alcohol F3 is preferred.



Specific fluid/temperature/time laboratory studies are recommended for all high-pH fluids containing oxidizing breakers or alcohol stabilizers. Fluid performance and proppant cured-strengths must be described for the application.



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Fig. 9. Curable resin-coated proppant compressive strength required to prevent flowback. 2.6 FracCADE Software The FracCADE options pertaining to the HyPerSTIM Service and tip-screenout design are described in the following sections. A summary design procedure and example is provided to illustrate the design technique using the PLACEMENT II simulator. Detailed discussion of other module changes and additions such as MLF (Multilayer Fracturing Model) is provided in the FracCADE User's Manual, release notes and on-line help screens. 2.6.1 FracNPV and QUICK Modules Refer to Fig. 10, Proppant Editor screen, and Fig. 11, FracNPV screens for the changes.



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Fig. 10. Proppant Editor.



Fig. 11. FracNPV Input. Proppant Editor The inertial flow coefficient (Beta factor) is computed using Eq 11. Turbulence Constants “a” and “b” provided in the proppant data base are used when β is in atmsec2/gm units. Proppant permeability is in darcy units. NOTE— The FracIPR software uses β in ft-1 units and proppant permeability in md units, hence the constants are not interchangeable. The exponent “a” is numerically identical for both FracNPV and FracIPR input. The constant “b” required for FracIPR input may be obtained by multiplying the FracNPV equivalent by 1000 raised to the “a” power (bFracIPR = bFracNPV X 1000a).



Placement and Reservoir Factors Modifications to the FracNPV and QUICK modules include the addition of two “safety factors” to account for the analytical fracture model limitations, uncertainties of fracture design, proppant placement and apparent producing length. The design length is reduced by the Placement Factor to adjust for the effective propped length relative to hydraulic length. This accounts for increased fluid loss to fissures, height growth and reduced proppant transport from gravity current. The apparent fracture length for production purposes is obtained from the Reservoir Factor, which is the DOWELL CONFIDENTIAL



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fraction of the propped length. The Reservoir Factor accounts for nonideal reservoir behavior such as layered, anisotropic and stress-sensitive permeability. Respective default values are 0.7 and 0.6 for the placement and reservoir factors. These may be modified based on local experience. Additional information is provided in Nolte, K.G., and Economides, M.J.: “Fracture Design and Validation with Uncertainty and Model Limitations,”JPT (Sept 1991) 1147-1155.



Include Turbulence Effect (Yes/No) The option for inclusion of the non-darcy effect is provided for gas wells only, and should be used to approximate the effect on production for all high-rate gas wells. The equations used to correct dimensionless fracture conductivity are discussed in Section 2.5.2. The assumptions and limitations of the non-darcy correction to dimensionless fracture conductivity include the following. • Non-darcy flow exists within the propped fracture only. All flow is through the fracture. It should be noted that non-darcy flow may also exist in the matrix of wells with very short effective wellbore radii and limited matrix damage. •



Flow rate (velocity) at the well bore is used and considered constant for the entire fracture length. The Reynolds number coefficient (c), given in Eq. 15 (to correct for flow geometry and rate variance) is 0.31. The FracNPV module does iterate on flow rate, and adjusts the Reynolds number appropriately with time, thereby reducing the velocity effect.



•



Gross fracture height and average fracture width is used to compute the effective flow area and Reynolds number. The FracNPV module assumes the entire gross fracture height is propped. The impact of non-darcy flow is therefore under estimated if gross fracture height is larger than either gross formation interval or propped height. If net interval height is used, the result is an over-estimation of non-darcy effects when the propped gross formation thickness is greater than net thickness (multi-layer zones).



FracNPV Output An additional output page (Fig. 12) has been provided in the engineering report displaying the predicted equivalent wellbore radius and pseudo-skin for each fracture length and time. The information may be used for construction of decline curves using the SAM software or for evaluation comparison to actual skin obtained. When the dimensionless time, tDxf, is less than 10, the equivalent wellbore radius is computed from rw′ = re /(e[PD+0.75]) where PD is the type-curve dimensionless pressure function at each dimensionless time. When the dimensionless time is greater than 10, the equivalent wellbore radius for pseudo-radial flow is calculated from the Prats and Cinco-Ley/Samaniego correlation (represented in Fig. 5). The pseudo-skin is obtained using Eq. 4. The data will be of value primarily for low- and moderate-permeability wells during the transient flow period. The output will have limited use for high-permeability wells. As the dimensionless time and pressure become large (most high-permeability DOWELL CONFIDENTIAL



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cases) the effective wellbore radius will decrease and pseudo-skin will increase during the transient period.



Fig. 12. Equivalent wellbore radius and pseudo-skin. 2.6.2 The FORECAST Module Fig. 13 illustrates the FORECAST module screen changes.



Fig. 13. PRODUCTION FORECAST input.



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The FORECAST module should be used to estimate production response for highpermeability wells, within the assumed constraints of boundary conditions and drive mechanism. The non-darcy flow effect has been incorporated within the production forecast calculation for gas wells. The “Include Turbulence Effect” flag is defaulted to YES for gas wells. If set to NO, the Turbulence Constant values from the proppant data base are not displayed. The fields are also blank when an oil well is specified. The FORECAST module computes the non-darcy flow effect using a correction to fracture capacity described by Holditch, which is similar to the previously discussed Gidley correction. The differences in computation procedure and output compared to the FracNPV computation procedure and output are described below. • Non-darcy flow is considered within the fracture only. The fracture is divided into cells and the flow through each cell is treated individually. The flow velocity and Reynolds number is computed for each cell cross-sectional area, and the correction is applied to the conductivity of the respective cell. The average cumulative velocity is used to correct successive cells approaching the wellbore. The numerical approach results in reduced non-darcy effects within the fracture at length. As with the FracNPV computation, the β factor is computed from Eq. 11. •



The gross fracture height (assumed continuous and propped) and respective fracture cell cross section is used to determine the flow velocity. This is consistent with the FracNPV analysis and may result in overcorrection as previously discussed.



Example output illustrated in Fig. 14 compares FracNPV and FORECAST computations for the same high-permeability gas well described (Fig. 11 and Fig. 13), with equivalent fracture parameters and the following propped interval heights. Gross fracture height — 120 ft Gross formation height — 94 ft Net formation height — 50 ft



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Fig. 14. Production simulation, non-darcy flow. The procedures described in Section 2.5.2 should be used to minimize the impact of non-darcy flow. 2.6.3 The PLACEMENT II Simulator A pseudo-three dimensional (P3D) model has been incorporated into the PLACEMENT numerical fracture simulator. The simulator is now capable of modeling fracture growth into layers above and below the pay interval. The simulator will also model fracture extension or recession. The latter capability is important in the fracture design for high-permeability formations to model wide fractures created by tip-screenout conditions, enabling pumping simulation after proppant bridging. In addition, the short fractures often created for skin bypass may be simulated through the use of a new “lateral coupling” option (P3D_LAT). This represents a gradual evolution from KGD to radial to PKN pressure behavior. A brief overview of the changes and features of the PLACEMENT II simulator follows. Discussion of the new multilayer and fracture acidizing modules in the FracCADE software are not covered. The FracCADE User's Manual release notes and on-line help screens provide additional information.



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General Modifications A PERFORATIONS screen has been added in the FracCADE software to allow for definition of multiple-perforation intervals required by the multilayer fracture module. Previous reference to perforations on the WELL screen has been deleted. Nonoverlapping perforated intervals must be entered in order of increasing depth. The RESERVOIR screen has been modified to reflect produced reservoir fluid properties only. PVT correlation data is provided in a new ZONES screen.



ROCK Screen The ROCK screen (Fig. 15) in the FracCADE software has been changed. The screen defines the various layer rock data for a maximum of 10 rock types. Tipscreenout design requires accurate data from core evaluation. As previously discussed, the defaults for Young's modulus are lithology and porosity dependent. The compressibility is a function of input porosity only. The default values should be used with caution.



Fig. 15. ROCK input. ZONES Screen The ZONES Screen (Fig. 16) has been introduced to define the stress profile and variation of rock properties with depth. A maximum of 20 contiguous zones may be defined. The left portion of the screen displays the detailed properties of the individual zone indexed. Only one zone may be defined for 2D simulations (all modules but MLF and PLACEMENT P3D), however, if more than one zone is defined, then the 2D modules will use the properties of the zones defined in the field entitled Zones for 2D Calculations From (also present on other screens). Refer to the user release notes for details on how the equivalent 2D properties are determined and screen functions.



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Fig. 16. ZONES — layer data input. PLACEMENT Screen Fig. 17 illustrates the changes to the PLACEMENT SIMULATOR screen. The leakoff coefficient and spurt fields were added to support the USER leakoff model (discussed below). The Model Poroelasticity (Y/N) field allows the P3D model to include this effect on pressure and width. The field entitled Temp. Model allows a choice between a constant bilinear temperature profile throughout the treatment or a general transient numerical solution to heat flow in the fracture. This option is available in the PLACEMENT II simulator only. The fields entitled Top Barrier Flag and Bot(tom) Barrier Flag specify the action to be taken during a P3D PLACEMENT II simulation if the fracture height reaches the top or bottom of the defined zones. The barrier zones are assumed to extend to infinity to allow continued height growth or fluid loss is assumed high enough to restrict any further height growth. The following describes the assumptions and limitations of the P3D model in the FracDADE software. • Individual cross sections of the fracture act independently. The pressure/width relation is independent of length and is only a function of rock mechanical property and fracture height. If the P3D_LAT lateral coupling option is invoked, the pressure at any cross section will depend on the pressure everywhere in the fracture (sections do not act independently). The correction is small for long fractures, however, the correction may be significant in the case of short fractures. The P3D_LAT option should be used where fracture height-to-halflength ratio is greater than 1.0 or for simulation of early-time pressure data. •



Fracture toughness (fracture tip-effect) is considered.



•



Fluid flow is horizontal. The pressure loss in the vertical direction is due only to hydrostatic gradient. Flow into the fracture occurs over the full height. Large



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relative fluid losses (greater than 60%) to low-stress porous intervals above the pay interval are not accurately modeled because vertical flow is ignored. •



Layers immediately above and below the pay interval must have higher stress levels than the pay interval. The overall profile entered must be able to contain the fracture (upper and lowermost intervals must act as barriers). The thickness of any barrier is also limited by the stress contrast between the barrier and the pay zone.



•



A constant- or variable-leakoff model with variable-leakoff rates into different zones is supported in the FracCADE software. A USER input leakoff coefficient may be used as an alternate. The USER specified value is assumed to be a single, constant-leakoff coefficient for all fluids everywhere within the fracture.



•



Clean (no proppant) fracture-fluid properties may be specified as constant or varying.



•



Two screenout modes, bridging and dehydration, are possible with continued pumping. The fluid is assumed to flow through the point where proppant has bridged. When a screenout occurs, the fracture stops growing in height and length and the proppant concentration increases. Bridging may occur at some point far from the fracture tip.



•



The P3D model uses proppant-bridging criteria based on the average diameter of the proppant and average cross-sectional fracture width (approximately threefourths of the maximum width). Along with the effect of poroelasticity, the total result may produce proppant bridging earlier than experienced with an equivalent single-layer 2D design.



Fracture Tip-Screenout Design With the treatment candidate, fracture fluid and proppant selected using methods previously described, the following example well data is used to illustrate the use of the PLACEMENT II simulator.



Example Design Parameters— Permeability, porosity and rock parameters per Fig. 15 and Fig. 16 Bottomhole static temperature, 200°F (93°C) Fluid — YF140D Ct (from DataFRAC Analysis), 0.005 ft/min½ Fracture half length is approximately 100 ft Dimensionless fracture conductivity greater than 1.5, maximize within constraints Maximum allowable pressure increase after screenout is 1500 psi Maximum pump rate, 10 bbl/min



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Procedure 1. Use a manual calculation or computer-aided software (PROPPIC or FracCADE) to aid proppant selection. The FracNPV module is used to aid selection of proppant and fracture length target for this example. (The spacing was increased to maximum to approximate limited depletion. Caution must be exercised to ensure cumulative production does not exceed recoverable reserves within actual spacing limit.) 2. Use appropriate 2D equivalent geometry and a pump schedule routine such as the INVERSE module to design a conventional treatment. This will establish an initial trial pump schedule for the penetration and maximum prop concentration specified. 3. When considering first design proposals without DataFRAC Service input, the P3D model may be used initially to estimate equivalent 2D geometry and to calibrate the Placement Factor. 4. Select P3D or P3D_LAT geometry and rerun the PLACEMENT module, increasing the volume of high-concentration slurry in the last one or two stages. In the majority of cases, increased pad volume will be required to prevent premature bridging, because of potential height-growth and the slight differences in bridging criteria between the 2D and P3D models. Intermediate stages may be adjusted (through the INVERSE module fluid correction and proppant reduction factors) if required for uniformity or tapering of propped fracture concentration.



Discussion of Results The effect of non-darcy flow for this oil well was insignificant and was not considered. Proppant embedment effect was minimal with an estimated 0.12 or 0.21 lbm/ft2 additional concentration required for 20/40- and 12/20-mesh proppant respectively. Proppant permeability and concentration sensitivity studies indicated benefits by using 12/20-mesh sand at maximum concentration (xf = 100 to 150 ft, avg CfD = 1.5) instead of 20/40-mesh sand (50 to 100 ft, avg CfD = 0.5). For the example 12 md well, stimulation is possible (S = -3 to -4). Two options are reviewed: (1) using 20/40-mesh proppant and increasing the width to achieve equivalent 12/20-mesh CfD of 1.5, and (2) using 12/20-mesh proppant, further improving dimensionless fracture conductivity and incrementing production. Fig. 17 and Fig. 18 illustrate the conventional design pump schedule and geometry using 20/40-mesh proppant. Fig. 19 and Fig. 20 illustrate the revised schedule and the resulting increase in dimensionless fracture conductivity, propped concentration and net pressure. When considering the larger 12/20-mesh proppant, additional pad volume is required for both the conventional 2D and P3D screenout-design to eliminate early bridging. Fig. 21 and Fig. 22 provide the conventional schedule and created geometry. Fig. 23 and Fig. 24 provide the screenout schedule and created geometry. For reasons previously discussed (poroelasticity and bridging criteria), the P3D DOWELL CONFIDENTIAL



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simulation indicated premature bridging of the 12/20 proppant at 64 ft. In practice, assuming accuracy of the simulator bridging criteria at 2.5 average grain diameters, improving fluid efficiency through rate increase may provide the only recourse to enable use of 12/20-mesh proppant for this case. Rate and proppant transport limitations may preclude exclusive use of 12/20-mesh. An alternate approach using a 20/40-mesh proppant stage ahead of the 12/20 may be considered.



Graphical Output Fig. 25, Fig. 26, Fig. 27, Fig. 28, and Fig. 29 provide the basis of the graphical output changes for the PLACEMENT II simulator. Most of the figures are self-explanatory. Fig. 25, Stage Front Propagation, shows the fluid front development versus time. For this example, the 20/40-mesh proppant bridged at approximately 100 ft (7.4 min into the treatment). The pad and only the fluid portion of the 2 PPA and 4 PPA fronts (less proppant) continued to move through the pack during the remaining pump time until the leakoff rate in front of the proppant pack exceeded the fluid rate through the pack. The fluid front then receded toward and across the pack until pumping ceased.



Note —When a screenout occurs near the fracture tip, fracture length and leakoff area become restricted. Fracture fluid efficiency increases due to the elimination of spurt losses and the existence of a well-developed filter cake. The use of a higher leakoff coefficient for the slurry (as compared to the pad fluid) should be considered. This will allow rapid concentration of the proppant and will provide reduced fracture closure time with minimum proppant settling. PLACEMENT II simulation time may be extended significantly if closure time is long.



3 Execution The differences between high-permeability fracturing and conventional fracturing are reduced treatment sizes, batch mixing requirements and lack of conventional fracturing equipment in a “non-frac” area. Short pump times will enable the use of limited-stability fluids using the CleanFRAC Service with high breaker concentrations to maximize conductivity. Larger treatments designed for tip screenout will require continuous-mix POD* blender capability. Logistics in many offshore environments may dictate equipment constraints. 3.1 Batch-Mix Operations Batch-mix operations are applicable for the following. • Skin-bypass treatments when proppant slurry volumes are generally less than 4000 gal Offshore environments and remote areas with limited access to fracturing equipment can use existing pumping and batch-mixing capability. As few as



*



Mark of Schlumberger



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•



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one 250 HHP pump has been used to successfully fracture at 5 bbl/min placing 2000 lbm of proppant at 8.5 PPA in YF140. Pump rates limited to less than 12 bbl/min At lower pump rates (less than 4 bbl/min per pump), recirculation of batchmixed slurry through suction manifolding may be required for linear fluids. For batch-mix treatments at higher rates (greater than 12 bbl/min) modifications to slurry batch-mix centrifugal pumps and manifold equipment (six to eight in. diameter) may be required. When the concentration of proppant is generally limited to one (8 to 12 PPA) or two (2 to 4 and 8 to 12 PPA) stages. Tip-screenout design is more difficult to apply due to lack of volume and ramping capability.



3.2 Continuous-Mix Operations Conventional fracturing equipment has advantages in the execution of the tipscreenout design. • The POD blender should be used for accurate control of the short- and highconcentration proppant ramps. •



A stage of low-concentration proppant (1 to 2 PPA) ahead of the ramp to establish fracture entry and initiate the tip screenout is recommended as part of the design. A low-concentration stage ahead helps to minimize “pack-back” of the proppant. This stage also allows time to switch the blender to automatic control.



•



When confidence in the input parameters or design model is low, a provision may be made to lengthen, at fixed concentration, the stage during which the tip screenout is predicted. If net pressure is calculated from surface pressure, the stage should be sized to fill the wellbore and tubulars so that screenout pressure rather than friction pressure is reflected.



•



In the event fracture-tip screenout and a net pressure increase is not evident during the remaining 10% to 20% of slurry volume and displacement, rate reductions may be used to reduce hydraulic width, accelerate fracture closure and avoid fracture propagation after shut down. Rate reductions during a net pressure increase may also be required to avoid overpressure.



4 Evaluation In moderate- to high-permeability reservoirs, evaluation of finite-conductivity fractures may not be possible using conventional type-curve, and bilinear-flow analyses of post-fracture pressure-buildup data. The existence of the characteristic one-quarter slope on the log-log diagnostic plot of differential pressure and derivative versus time is required, and its presence provides an indication of stimulation. DOWELL CONFIDENTIAL



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Gas well evaluation should consider the effects of non-darcy flow during the buildup period and the resulting apparent fracture conductivity variance with time (Holditch/Morse, Tannich/Nierode). A numerical simulator accounting for non-darcy flow effects must be used to history-match the data for these conditions. 4.1 Prats’ Correlation 1.



In the majority of high-permeability cases, the short bilinear flow period will not be observed and a pseudo-radial flow regime may be analyzed (Horner plot) to determine the effective skin.



2.



The effective wellbore radius may then be estimated using Eq. 4 and compared to predicted value.



3.



The predicted apparent dimensionless fracture conductivity and are used to obtain the dimensionless ratio of rw′/xf.



4.



With the calculated effective wellbore radius and the ratio known, the effective fracture length may be computed.



4.2 Modified McGuire-Sikora Correlation 1.



An alternate approach using Fig. 4 may be used. The ratio of undamaged productivity potential (Eq. 16 and Eq. 17) versus the actual observed rates, defines the pseudo-steady-state folds of increase.



2.



From the appropriate well spacing and folds increase value, a horizontal line may be drawn to the intersection of the predicted dimensionless fracture conductivity (or conductivity ratio kfw /kre) and corresponding xf /re.



3.



The fracture length may then be computed from the xf /re value and compared to the predicted length.



Evaluation using pseudo-steady-state flow rates will be sensitive to the average differential pressure used to compute rate. Factors such as depletion (avg. Pe) and non-darcy pressure losses should be considered (numerical reservoir simulation and history matching). In some cases, limited drawdown may introduce inaccuracies in differential pressure for rates quoted.



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Fig. 17. PLACEMENT SIMULATOR — conventional design, 20/40-mesh sand, 1400 gal pad.



Fig. 18. PLACEMENT OUTPUT — conventional design, 20/40-mesh sand.



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Fig. 19. PLACEMENT SIMULATOR — P3D tip-screenout design, 20/40-mesh sand, 1600 gal pad.



Fig. 20. PLACEMENT OUTPUT — P3D tip-screenout design, 20/40-mesh sand.



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Fig. 21. PLACEMENT SIMULATOR — conventional design, 12/20-mesh sand, 1800 gal pad.



Fig. 22. PLACEMENT OUTPUT — conventional design, 12/20- mesh sand.



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Fig. 23. PLACEMENT SIMULATOR — P3D tip-screenout design, 12/20-mesh sand, 3500 gal pad.



Fig. 24. PLACEMENT OUTPUT — P3D tip-screenout design, 12/20-mesh sand.



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Fig. 25. Stage front propogation.



Fig. 26. Fracture height profile DOWELL CONFIDENTIAL



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Fig. 27. Wellbore fracture width profile.



Fig. 28. Fracture height growth history. DOWELL CONFIDENTIAL



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Fig. 29. Fracturing (net) pressure profile.



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5 Fluid-Loss Data 5.1 WF120 (J164) Containing 25 lbm J478/1000 gal and 25 lbm J418/1000 gal BHST=150°°F (66°°C), Pressure=1000 psi



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5.2 WF160 (J164) Without Fluid-Loss Additives  BHST=150°°F (66°°C), Pressure-1000 psi



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5.4 WF110 (J424) Containing 50lbm J238/1000 gal  BHST=150°°F (66°°C), Pressure1000 psi



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5.6 WF130 (J424) Containing 50lbm J238/1000 gal  BHST=150°°F (66°°C), Pressure-1000 psi



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5.8 WF160 (J424) Containing Various Fluid-Loss Additives  BHST=150°°F (66°°C), Pressure-1000 psi



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Acid Fracturing



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ACID FRACTURING 1 Principles of Acid Fracturing.................................................................................................. 2 1.1 Fracture Length and Fracture Conductivity.......................................................................... 4 1.2 Factors Affecting Acid Behavior in Carbonate Reservoirs ................................................... 6 1.2.1 Acid Type, Strength, and Volume ............................................................................... 6 1.2.2 Acid Leakoff ................................................................................................................ 9 1.2.3 Controlling Acid Leakoff............................................................................................ 14 1.2.4 Acid Reaction Rate ................................................................................................... 15 1.2.5 Acid Spending Time.................................................................................................. 17 2 Treatment Design Fundamentals for Acid Fracturing........................................................ 18 2.1 Achieving Acid Penetration ................................................................................................ 19 2.2 When Acid Fracture Length Should be Maximum.............................................................. 19 2.3 When Acid Fracture Length Should be Limited.................................................................. 19 2.4 Maximizing The Injection Rate ........................................................................................... 20 2.5 Optimizing Conductivity and Etched Fracture Length ........................................................ 20 2.6 Effective Acid Concentration .............................................................................................. 21 2.7 Selecting Fluids for Deeper Acid Penetration .................................................................... 22 2.8 Determination of Leakoff Coefficients ................................................................................ 24 2.8.1 Methodology ............................................................................................................. 24 2.8.2 Example Calculation ................................................................................................. 29 2.8.3 Notes ........................................................................................................................ 31 2.9 Cooldown ........................................................................................................................... 31 2.10 Retarded Acid .................................................................................................................. 33 2.11 Viscous Fingering ............................................................................................................ 36 2.12 Summary of Treatment Design Fundamentals for Acid Fracturing .................................. 37 FIGURES Fig. 1. Conductivity ratio versus increase in folds. ....................................................................... 5 Fig. 2. Acid spending in carbonate rock. ...................................................................................... 8 Fig. 3. Casting of a typical wormhole pattern in limestone......................................................... 12 DOWELL CONFIDENTIAL



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Test results, carbonate cores and wormholes.................................................................12 Test results, carbonate cores and wormholes.................................................................13 Test results, carbonate cores and wormholes.................................................................13 Viscosity of fresh water versus temperature....................................................................25 Spending time versus HCl concentration at static conditions. .........................................35 Temperature versus retardation factor at dynamic test conditions..................................36 TABLES



Table 1. Factors that Influence Fracture Conductivity and Fracture Penetration when Acid Fracturing a Carbonate Reservoir ..................................................................................6 Table 2. Acid Types and Strengths Common to Oilfield Operations ............................................9 Table 3. Total Minimum Leakoff Coefficients versus Temperature and Permeability ................26 Table 4. Scale Factor Base Values (SFb) ...................................................................................27 Table 5. Scale Factor Corrections ..............................................................................................28 Table 6. Retardation Factor Selection Guidelines ......................................................................34



1 Principles of Acid Fracturing Acid fracturing, also called fracture acidizing, is a stimulation process in which acid, usually hydrochloric acid (HCl), is injected into a limestone or dolomite formation at a pressure sufficient to fracture the formation or to open existing fractures. As the acid flows along the fracture, portions of the fracture face are dissolved. Since flowing acid tends to etch in a non-uniform manner, conductive channels are created which usually remain after the fracture closes. The length of the etched fracture is determined by the acid type, strength, volume, acid leakoff parameters, reaction rate and spending rate. These factors are mutually dependent upon each other. The effectiveness of the acid fracturing treatment is largely determined by the length of the etched fracture. As with conventional hydraulic fracturing operations, the principal objective of an acid fracturing treatment is to provide a conductive fracture with sufficient length to allow efficient drainage of the reservoir. The major difference between the two treatment techniques is how the conductivity is achieved. In conventional propped fracturing treatments, sand or other proppant is placed in the fracture to prevent closure when fracturing pressure is released. Acid fracturing does not normally utilize propping agents but relies upon acid-etched fracture faces to provide the necessary conductivity. Acid fracturing is generally limited to the cleaner, higher solubility, limestone or dolomite (carbonate) formations. Dirty carbonate rocks (less than 70% solubility in HCl) are not candidates for acid fracturing for the following reasons: • The creation of acid-etched flow channels will be impaired because of low solubility.



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The release of insoluble materials will tend to plug any conductive etch patterns created by the acid.



Although normally possessing high acid solubility, chalk formations may not be suitable acid fracturing candidates because of the soft character of the rock. The rock must be sufficiently competent to retain conductivity after closure of the etched fracture. Acid fracturing is never used in the treatment of sandstones because acid, even hydrofluoric acid (HF), will not adequately etch sandstone fracture faces. Even if the sandstone is cemented with a carbonate cement, materials released through the dissolution of the carbonate cement will plug the fracture. In some carbonate formations, a choice exists between acid fracturing and proppant fracturing. Each technique has advantages and disadvantages. If similar productivity can be achieved by either procedure, the choice is usually a nonreactive fracturing fluid with proppant because of economic considerations. Acid fracturing of reservoirs having bottomhole static temperatures in excess of 250°F (121°C) can be expensive because of increased corrosion inhibitor requirements, especially on steels normally used under such conditions (13% chrome, duplex). A tradeoff of costs can be achieved by using the cooldown effect of the pad on the well tubulars and adding only sufficient corrosion inhibitor to provide corrosion protection at the cooldown temperature. The savings in inhibitor costs may be negated by the costs of additional and appropriate standby equipment to continue and complete the job, should it become necessary. Operationally, acid fracturing is less complicated because propping agent is not used. Also, the danger of screenout and the associated problems of proppant flowback and cleanout from the wellbore are eliminated. In addition, the fracturing fluid proppant transport characteristics are not a concern with acid fracturing. In deep carbonate wells, acid may be the best fluid for fracturing operations if proppant flowback, crushing or screenout are a problem, despite the corrosion problems mentioned above. While the use of acid as a fracturing fluid eliminates some difficulties inherent with proppant fracturing, there are problems of a different nature. For example, when comparing a propped fracture and an acid-etched fracture, the effective length of the propped fracture is limited by the distance the proppant can be transported down the fracture. In a similar manner, the effective length of the acid-etched fracture is limited by the distance the acid can travel along the fracture and adequately etch the fracture faces before becoming spent. The effective acid penetration is always shorter than any proppant placement, especially at elevated temperatures. An acid fracturing design should take into consideration the following: • The fracture should be propagated to the desired length in the reservoir. •



The walls of the fracture should be etched with an acid capable of dissolving large amounts of reservoir rock.



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The etched fracture should retain adequate length and conductivity after closure.



•



Rapid cleanup of treatment fluids should be achieved.



•



The acid fracturing treatment should be the most cost-effective (best value) treatment for the client.



Summary The best application for acid fracturing may be in low-permeability carbonate reservoirs having a limited number of natural fissures. Chalk formations can be a problem because of soft characteristics (the acid-etched fracture may collapse). Proppant fracturing may be best in deep, carbonate reservoirs because the depth, high temperatures, and high closure pressures are detrimental to the length and conductivity of an acid-etched fracture. In addition, corrosion inhibition costs are usually high in these situations. 1.1 Fracture Length and Fracture Conductivity The objective of an acid fracturing treatment, like a conventional proppant fracturing treatment, is to create a conductive fracture with sufficient length to provide effective drainage of the reservoir. The McGuire and Sikora stimulation curves (Fig. 1) relate the fundamentals of relative conductivity and fracture penetration to the drainage radius. The relative conductivity is a comparison of the induced fracture permeability and the unstimulated reservoir permeability. The curves indicate that a high conductivity ratio and a deeply penetrating flow channel are both necessary for significant productivity increase. Alone, neither of them will provide stimulation. These principles (conductivity and penetration) apply whether proppant fracturing or acid fracturing. When acid fracturing, the etched length, not the hydraulic length, is considered the fracture length. Fracture conductivity, when acid fracturing, is created by dissolving reservoir rock. When a given volume of acid is pumped into a carbonate reservoir, a specific amount of reservoir rock will be dissolved by the acid. The created void represents conductivity. In order for an acid fracturing technique to be successful however, the conductivity must be optimized by assuring that reservoir rock will be dissolved in a manner that will provide highly conductive flow channels. Hydrochloric acid reacts with carbonate rock in a nonuniform manner, that is, fingerlike channels are created along the fracture faces. The area between these channels serve as pillars. When the fracture closes, the channels remain, providing high conductivity. Acid fracture conductivity and acid fracture penetration (both are necessary for reservoir stimulation - see Fig. 1) are governed by many factors. An understanding



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of these factors and how they interrelate is necessary when considering stimulation by acid fracturing. These factors are shown in Table 1. There are five prerequisites for reservoir stimulation using acid. 1. The acid must dissolve reservoir rock and form soluble by-products that can be returned from the well. 2. Corrosion inhibition must be relatively inexpensive. 3. Components of the acid fracturing treatment must be relatively safe to handle. 4. The acid fracturing fluid must be readily available. The acid fracturing treatment must be relatively inexpensive.



Fig. 1. Conductivity ratio versus increase in folds.



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Table 1. Factors that Influence Fracture Conductivity and Fracture Penetration when Acid Fracturing a Carbonate Reservoir •



Acid Type



•



Acid Strength



•



Acid Volume



•



Acid Leakoff



•



Acid Reaction Rate (Acid Spending Time)



•



Acid Viscosity



•



Injection Rate



•



Formation Mineralogy



•



Formation Temperature



•



Formation Wettability



•



Reservoir Fluids



•



Fracture Net Pressure



•



Closure Pressure



1.2 Factors Affecting Acid Behavior in Carbonate Reservoirs 1.2.1 Acid Type, Strength, and Volume The most common acid used in the oilfield for acid fracturing is hydrochloric acid. HCl is a strong mineral acid. Weak organic acids such as formic (HCOOH) and acetic (CH 3COOH), are also used. The dissolving power of organic acids is much lower than that of HCl. Organic acids do, however, have the characteristic of being easier to inhibit against corrosion than HCl. Organic acids have been used in blends of hydrochloric and formic acids or hydrochloric and acetic acids. These blends have been thought to provide a degree of retardation of the acid so that live acid could be pushed further down the fracture, creating conductivity deeper in the reservoir. Under most conditions, however, when the HCl spends, the weak organic acid, although unspent, lacks the reactivity to adequately etch the fracture faces. Formic acid, acetic acid and organic acid mixtures have been used to fracture reservoirs with bottomhole static temperatures greater than 300°F (149°C). Development of more efficient corrosion inhibitors along with well cooldown procedures have diminished the use of formic and acetic acids. They are however sometimes used as the breakdown fluid in high temperature reservoirs prior to fracturing operations using proppant. Corrosion inhibition of organic acids at high temperatures is easier than corrosion inhibition of HCl.



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Chemically, whether an acid is defined as a strong acid like HCl or as a weak acid like either formic or acetic depends upon the rate at which the acid ionizes as an electrolyte. An electrolyte is an aqueous solution that has the capability of transmitting an electric current. The defining parameter to establish whether an acid is strong or weak is the rate at which its acid solution transmits electric current. Consider a hypothetical acid, HA, which has an acid ion H+ and a negative ion A-. Whether it is a strong acid or a weak acid depends upon how fast its acid ion, H+, dissociates (ionizes) from the negative A- ion in a water solution. HCl, in water, instantly and completely ionizes into its component ions (H+,Cl-). Instant ionization takes place regardless of the acid concentration in water from 3 to 37% (by weight). Thus, to be technically correct, lesser concentrations of HCl (for example, 3% to 5%) are more properly defined as dilute acid solutions rather than weak acid solutions. Because total dissociation of HCl is instant, its ionization constant is infinite. Formic acid, in water, ionizes into its component ions slower than HCl but faster and more completely than acetic acid. Both are much weaker acids than HCl. Being defined as weak acids does not mean they are less hazardous to health, instead, `weak' defines the degree of ionization. Both these organic acids are very corrosive to flesh. Material Safety Data Sheet provide safe handling procedures for the various acids. The chemical equation for reaction of hydrochloric acid with limestone (CaCO3) is shown below in mass-balanced form. Note that the reaction products are soluble in water and can be readily recovered from the well. CaCO3 + 2 HCl → H2O + CO2 ↑ + CaCl2 (Limestone) + (Acid) → (Water) + (Gas) + (Salt) The reaction products are water, carbon dioxide gas and calcium chloride salt. Hydrochloric acid is the most common type of acid used in the oil field. HCl is variously inhibited, stabilized, retarded, gelled, blended with other acids, foamed, misted, emulsified and nonemulsified. Other additives include friction reducers, surface-tension reducers, mutual solvents, chelants, fluid-loss control additives, water-block removers, viscosifiers, scale inhibitors, paraffin inhibitors, additives to cause heating, diverting agents, clay stabilizers and clay dispersers. The usual HCl concentrations in acid fracturing are 15, 20 and 28%. The other two familiar types of acids used in the oil field, formic acid and acetic acid, also react with limestone to form water, gas and a salt. These weak organic acids do not completely spend in carbonate reservoirs but buffer themselves with the reaction products present in the partially spent acid. Depending upon reservoir temperature and acid concentration, these organic acids will spend to a certain point and no further. (See Fig. 2 and Table 2. HCl is shown only for reference. It spends to completion at all temperatures.) The effect of higher temperatures on organic acids is to decrease reactivity in carbonate reservoirs. Additionally, neither of these organic acids should be used at concentrations above 9% formic or 10% acetic



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since, when spent, high concentrations of organic calcium salts may precipitate in the formation:



Formic Acid CaCO3 + 2 HCOOH → H2O + CO2↑ + Ca(HCOO)2 (Calcium formate)



Acetic Acid CaCO3 + 2 CH3COOH → H2O + CO2↑ + Ca(CH3COO)2 (Calcium acetate)



Fig. 2. Acid spending in carbonate rock. Table 2 lists several different acid types and strengths common to oilfield operations. Note that a considerable amount of CO2 can be generated by the acids. Gas expansion is a potential energy that can be used to help recover the treatment load by back-flowing the well as soon as possible after shutdown of the fracture acid treatment. DOWELL CONFIDENTIAL



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As stated previously, a given amount of acid will create a given amount of etched fracture width. Higher volumes and higher strengths will create even more etched fracture width. This can be translated into useful fracture conductivity providing that the rock that has been dissolved is in the form of deeply penetrating flow channels etched into the fracture faces.



Table 2. Acid Types and Strengths Common to Oilfield Operations Acid Type



Acid Strength (%)



lbm CaCo3 Dissolved by 1000 gal Acid



scf CO2 Generated per bbl Acid



Hydrochloric



15 20 28



1833 2515 3662



289 396 577



Formic+



9



726



60



Acetic+



10



422



30



+at 100° F(38°C) 1.2.2 Acid Leakoff During many acid fracturing treatments, the treating pressure declines continually, eventually falling below a level required to propagate the fracture. This decline in treating pressure is caused by the usually very large leakoff of the acid. The overall leakoff rate increases with fracture length, up to a point where it equals the injection rate and where net pressure is minimum and the fracture stops extending. Conventional hydraulic fracturing using nonreactive fluid relies primarily on wallbuilding fluid-loss additives to control leakoff. The filter cake deposited on the face of the fracture by the fluid-loss additive allows less and less fluid to leak off into the formation. This same kind of control is desirable when acid fracturing, but, because conventional filter cakes are destroyed by the acid or are negated by the reaction of acid dissolving rock from beneath the filter cake, other means have been developed to combat acid leakoff.



Natural Fissures and Fractures Carbonate reservoirs, especially dolomites, are normally more naturally fissured that sandstones. Fissures represent a particular path of least resistance for acid. The fissures get wider as more acid is introduced and thief away large volumes of acid from the induced hydraulic fracture. A reservoir may contain so many fissures that acid leakoff into them can limit the propagation of a hydraulic fracture to no more than tens of feet. In these reservoirs, a hydraulic fracture may be initiated but can not grow to extend past the first intersecting fissures.



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When the permeability of the fissures has the same order of magnitude as the matrix permeability, the reservoir has a double-porosity behavior. Pressure tests show two distinct periods of time, the earlier one related to the network of fissures, the second to the matrix itself. The overall reservoir permeability is then generally equal to 2 to 20 times the matrix permeability (the latter being determined through core testing). When dual-porosity behavior is suspected, plan first for controlling leakoff into the fissures. Both the viscosity-controlled leakoff and the compressibility-controlled leakoff are proportional to the square root of permeability. Thus if matrix permeability is 0.1 md and reservoir permeability is 1.7 md, control of leakoff into fissures reduces the leakoff rate by a factor of four. When fissure permeability overwhelms the matrix permeability, the reservoir tends to behave again as a primary porosity medium. In this latter case, it would be difficult to initiate a hydraulic fracture and any such fracture would provide very little production increase. However, high-rate acid treatments are common in these reservoirs. They make use of Mud and Silt Remover (MSR*)-type acids, NARS* formation solvent or highly concentrated surfactant pills, and are aimed at removing drilling mud losses from the fissures network. Such treatments are not acid fracturing treatments and cannot be designed using the present guidelines.



Wormholes During an acid fracturing treatment, the acid not only etches the fracture faces, it also leaks off into the reservoir perpendicular to the fracture faces. Live acid leaking into the porous fracture face creates voids called wormholes. These become irregular, meandering, highly conductive tubes that can penetrate several feet into the reservoir rock (see Fig. 3). They are caused by selective enlargement of the larger pores in the rock as it reacts with the acid. Once wormholes develop, more acid leakoff occurs primarily via these wormholes. There is little leakoff in the conventional sense. Wormholes divert large volumes of acid away from the primary fracture system, volumes which are then unavailable to etch the fracture face a further distance from the wellbore. The magnitude of leakoff due to the wormhole effect is very severe. Wormholes occur in porous limestone and dolomite formations. The same factors that govern the acid penetration along the hydraulic fracture also affect acid penetration into pores. Consequently, wormhole enlargement and etched fracture length are affected by many of the same factors. For instance, fracture etched length increases as injection rate and fracture width increase. Similarly, wormholing is enhanced by increased leakoff rate and increased pore diameter. (Note however, that when matrix acidizing, wormhole diameter may actually decrease as injection rate increases. This is because of the large number of wormholes that are attempting propagation at the same time and the extremely large area of rock that is contacted by a limited acid volume).



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This helps explain why wormholes form in the porosity of the rock matrix. The combination of large pore diameters and the high rate of acid molecules within the acid flow inhibits the reaction of acid at the pore inlet and, because the acid molecule tends to stay in the center of the flowing stream, supports the extension of deeper wormholes. This also helps explain why, as temperature increases, wormholes are less of a problem. The acid reaction rate is increased to the point that the acid will spend at the inlet of the rock pores, whatever the pore size. This occurs at approximately 225°F (105°C) in limestones and approximately 325°F (163°C) in dolomites when pore diameters are in the 0.5 to 2 micron range which is normally 1 to 10 md permeability. For lower matrix permeabilities, and therefore smaller pore diameters, the temperature limits shift considerably, down to approximately 100 °F (38°C) in limestones below 0.1 md. A compact carbonate reservoir with very low matrix permeability (below 0.1 md) does not experience wormholing under normal treating pressures, that is, normal differential pressure between fracture and reservoir. Conversely, hairline fissures with widths of several microns are as many initiators for wormholing at elevated temperatures, even up to 350°F (177°C). Fig. 4, Fig. 5 and Fig. 6 illustrate the results of laboratory testing of carbonate cores and wormholes created with HCl. The separate effects of temperature, rate and concentration are plotted versus wormhole penetration of similar Indiana limestone cores. For these tests, the diameter of the cores was one in. and length was 11.8 in. To summarize, the main effect of acid leakoff is to reduce the etched fracture length and provoke a significant reduction in real versus planned well performance. This is true in spite of the increased wormhole-induced permeability of reservoir rock along the induced hydraulic fracture near the wellbore.



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Fig. 3. Casting of a typical wormhole pattern in limestone.



Fig. 4. Test results, carbonate cores and wormholes. DOWELL CONFIDENTIAL



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Fig. 5. Test results, carbonate cores and wormholes.



Fig. 6. Test results, carbonate cores and wormholes. DOWELL CONFIDENTIAL



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1.2.3 Controlling Acid Leakoff Fluid-loss control during acid fracturing of carbonate formations presents problems unique to reactive fluids. Most fluid-loss additives and gelling agents that are effective in conventional nonreactive aqueous fracturing fluids are unstable in acid. As a result, special acid-stable additives must be used. In addition, acid flow along carbonate fracture surfaces produces constant chemical erosion, thus making it difficult for wall-building fluids to deposit an effective filter cake. Finally, the acid leakoff rate continuously increases all along the acid injection due to the development of wormholes. Various additives and treating techniques have been developed as means of controlling acid fluid loss. These include acid-swellable polymers, oil-soluble resins, injection of gelled water pad ahead of the acid, injection of gelled water pads alternately spaced within stages of acid and acid-gelling agents.



Natural and Synthetic Swellable Polymers Natural and synthetic swellable polymers have been used with limited success. These polymers do not readily dissolve in acid but form small swollen particles that act to block wormholes in the early stage of development. Natural swellable polymers degrade rapidly in acid at temperatures greater than 125°F (52°C). Synthetic, swellable polymers, developed to overcome this problem, perform well in the laboratory but field treatments sometimes result in poor or incomplete posttreatment cleanup.



Oil-Soluble Resins To be effective, additives must be stable in acid solutions at elevated temperature. Fluid-loss additives that are stable in hot acid, however, are generally very difficult to dissolve or degrade after the treatment. One method of overcoming this problem involves the use of mixtures of oil-soluble resins as acid fluid-loss additives. The major limitation of oil-soluble resins is the high concentration of additive required for fluid-loss control. At the required concentration of 200 lbm resin mixture/1000 gal acid, high additive-costs limit commercial application.



Injection of a Viscous, Nonreactive Fluid Ahead of the Acid The "Frac Pad and Acid" technique involves using a water-base fracturing fluid to initiate and cool the fracture and deposit an impermeable filter cake on the fracture face. Though widely used, tests have indicated that the filter cake is quickly eroded and penetrated by acid. Once this occurs, acid fluid loss is identical to that observed if no gelled pad were used. Pads of linear gels that do not build polymer cakes on fracture face produce a viscous filtrate which might be very efficient at controlling leakoff during the following acid stage. This is particularly true in gas reservoirs (even more when depleted) where the viscosity, compressibility coefficient (Cvc) is naturally very large. While the injection of a viscous, nonreactive fluid ahead of the acid provides only very limited acid fluid-loss control, there are other benefits. The tubulars through DOWELL CONFIDENTIAL



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which the acid must flow are cooled, reducing corrosion. The technique cools the fracture and increases fracture width, reducing acid spending rate and increasing live-acid penetration along the fracture. Additionally, using a viscous pad promotes acid fingering of the acid into the trailing edge of the pad, thus reducing the amount of reactive surface to which the acid is exposed, improving etched fracture length.



Injection of Gelled-Water Pads Alternately Spaced With Stages of Acid This procedure was developed by Dowell and is marketed as the DUOFRAC* II acid fracturing procedure. Using this procedure, the fracture is created by a gelled pad, after which alternating stages of acid and additional pad are pumped. The additional pad stages are designed to enter and seal wormholes created by the preceding stage of acid. Acid leakoff into wormholes is slowed and treatment efficiency is improved. The DUOFRAC II acid fracturing procedure has all the advantages of the Frac Pad and Acid technique and, in addition, controls acid leakoff to a greater degree. A fine particulate solid is often added to the pad stages to aid in fluid-loss control. Examples are 100-mesh sand, oil-soluble resins, and fine salt. These particulate solids help bridge wormholes and natural fractures, also reducing leakoff.



Gelled Acid Acid leakoff can also be reduced by gelling the acid. A viscous fluid has less tendency to invade pore openings than a water-thin fluid. This method of control has become widely used with the development of more acid-stable thickening agents. The effectiveness of these thickeners varies widely. Some viscous acid systems, like Leakoff Control Acids (LCA* fluids), are very effective. LCA fluids are excellent acid fracturing fluids. These polymer-base gelled acids have low initial viscosity and friction pressure properties. During leakoff, LCA fluids temporarily develop high viscosity which controls fluid loss by blocking wormhole growth and slowing acid entry into natural fractures. LCA fluids have low spent-acid viscosity which enhances cleanup. The Fracturing Materials ManualFluids provides additional information on highperformance leakoff-control fluids. Gelling agents such as guar gum, hydroxypropylguar (HPG), hydroxyethylcellulose (HEC), and carboxymethylhydroxyethylcellulose (CMHEC) have limited stability in HCl and are thus limited in application for gelled acid fracturing. 1.2.4 Acid Reaction Rate The definition of acid reaction rate is the number of acid molecules reacting with the carbonate rock per unit of time. Acid reaction rate is not to be confused with acid spending time. Reaction rate is the speed at which acid reacts. Spending time is the length of time required for the acid to spend. *



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There are two different mechanisms involved in the overall reaction rate of acid. 1.



The physical transportation of acid molecules (diffusion).



2.



The chemical reaction of acid and rock molecules (kinetic).



Both mechanisms can be slowed down by decreasing the temperature of the acid mixture; surface reaction by adsorbing protective layers on the rock surface.



Diffusion Physical transport of the acid molecules from the center of the induced fracture toward the fracture face involves diffusion-rate and convection-rate phenomena. Together, these two terms are called the mass-transport rate. Diffusion is the natural motion of the molecules of any fluid that depends upon temperature and their spontaneous movement from a region of higher to a region of lower concentration. Convection is the motion of molecules that occurs in a fluid submitted to gradients of temperature or pressure (thermic and hydraulic convections respectively). • Molecular diffusion is slowed by increasing the interaction between molecules and by putting obstacles in the path of the molecules. This may be achieved by the physical presence of products generated by the acid reaction. (See Kinetic on the following page, which presents a discussion of the chemical reaction of acid and carbonate rock.) Diffusion can also be reduced by decreasing the temperature.



*



•



Turbulence enhances random motion of molecules, thus if turbulence is suppressed, diffusion is slowed. Turbulence can be reduced by acid viscosifiers, friction reducers and wider fractures.



•



Reducing the acid leakoff rate reduces convection by slowing the movement of the acid molecules toward the fracture faces.



•



As the fracture width is increased, more time is required for a molecule having a given velocity to reach the fracture face.



•



Reducing the surface-reaction rate can be accomplished either by reducing the temperature or by insertion of a barrier between the acid and the rock. Temperature reduction can be achieved using cool-down techniques. A barrier can be in the form of an acid-resistant filter cake, presence of reservoir oil or any kind of hydrocarbon barrier material used in the treating fluid. Examples of relevant Dowell treatment fluids are Acid Retarder F98 retarded acid (F98 is a surfactant which strongly adsorbs on carbonate surfaces) and SuperX* Emulsion (the external oil or diesel phase acts as a barrier in the bulk of the fluid itself).



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Kinetic The chemical reaction of the acid molecules at the fracture face results in the recombination of the hydrochloric acid and the rock species into water-soluble salts, carbon dioxide, and water. When HCl acid reacts with dolomite, the recombination products are calcium and magnesium chlorides (CaCl2 and MgCl2), carbon dioxide, and water. The presence of these compounds in solution in the partially spent acid will help suppress movement of the acid molecules toward the fracture face. The chemical reaction rate is a function of the interaction of all factors previously discussed including temperature. 1.2.5 Acid Spending Time Acid spending time is defined as the time taken for acid to spend under treating conditions. In contrast, the term acid reaction rate (previously discussed) defines the rate that acid spends. In many cases, it may not be necessary to retard the reaction rate of HCl but simply to cause it to spend at the desired locations within the fracture. In other words, increase the effectiveness of the acid by causing it to spend within the fracture. The acid fracturing concept is basic: fracture with acid to dissolve rock along the fracture faces resulting in greater conductivity. Placing the acid in the right place along the induced fracture so the desired flow channels will be created is important. The time required for HCl to spend during acid fracturing is dependent upon many parameters. Since these parameters are constantly changing because of the chemical erosion of carbonate rock, these parameters affect each other. Each of these parameters; strength and volume of acid, acid leakoff rate, live and spent acid viscosities, acid injection rate, area-to-volume ratio, temperature and differential pressure contribute to the reaction. The reservoir properties of mineralogy, lithology, saturation and wettability also affect spending time. Area-to-volume ratio is defined as the ratio of surface area of rock in contact with a specific volume of acid. A large area-to-volume ratio shortens acid spending time; conversely, a small area-to-volume ratio will extend acid spending time. Formation mineralogy and lithology have an effect on spending time as do reservoir saturation and reservoir wettability.



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Mineralogy Different acid-soluble minerals exhibit different spending times even if other conditions are the same. Calcite and dolomite, each having a different spending time, are the predominant minerals found in carbonate formations and are the minerals that are targeted for dissolution. Other acid-soluble minerals include other carbonates, iron sulfides, halide salts (soluble in the acid make-up water), and, to a limited extent, clays and feldspars.



Lithology Lithology defines the physical properties of the reservoir rock, that is, the degree of mineral crystallization within the reservoir, the sequence of deposition, bedding within the rock and presence of other rock particles.



Oil-Saturated Reservoirs An oil-saturated reservoir will react more slowly with the acid than a water-saturated reservoir because the oil can form a temporary barrier between the acid and the rock.



Oil-Wet Reservoirs An oil-wet reservoir can have a greater barrier-effect than one that contains high oilsaturation. None of these reservoir factors are readily or significantly changeable. Thus, the acid fracturing technique should be tailored in a way that can reduce or negate detrimental reservoir parameters.



2 Treatment Design Fundamentals for Acid Fracturing This section contains information that can be of assistance to users of the FracCADE* software for the design of an acid fracturing treatment. This information is provided so the reader can have a better understanding about acid fracturing and its design parameters. These guidelines are not intended to be a substitute for FracCADE documentation and procedures. When determining the relative merits of different concentrations and different mixtures of acids and treatment techniques, the FracCADE software should be used to compare them using values derived under dynamic (flowing) conditions representing downhole parameters. Test data derived using static conditions are of little value. Since there are such a large number of variables (see Table 1) and an infinite number of ways these variables can interact with each other, the acid reaction factors given in this section should only be used to compare different acid systems or different pumping techniques or both. Selection should be based on the relative merits of the calculated values.



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2.1 Achieving Acid Penetration The effectiveness of an acid fracturing treatment is largely determined by the length of the etched fracture. Controlling acid fluid loss and reaction rate, with attention to the other governing parameters such as injection rate, viscosity and area-to-volume ratio provides the best opportunity to create a long, conductive fracture. 2.2 When Acid Fracture Length Should be Maximum Maximum acid penetration is desired most of the time. To obtain maximum acid penetration at a bottomhole static temperature less than 200°F (93°C), the first step of the treatment design is to select fluids that have the lowest leakoff coefficients. At temperatures greater than 200°F (93°C), acid reaction rate usually becomes the primary limiting factor and must be decreased. This is achieved using reservoir cooldown techniques or with acid retardation or both. Higher injection rates, wider fracture widths and higher acid concentrations always provide deeper acid penetration regardless of temperature and leakoff conditions. Additionally, the presence of effective stress barriers bounding the producing interval will allow lateral fracture growth. Where barriers exist, the objective is to cause the acid-etched fracture to penetrate deeply into the drainage radius of the well. 2.3 When Acid Fracture Length Should be Limited Carbonate reservoirs seldom contain stress barriers. Where there are no barriers to limit fracture height growth, a hydraulically induced fracture will grow in both vertical and lateral directions until the treatment is completed. In the case of minimizing or preventing water or gas production from above or below the producing interval, or in the case of preventing communication with other zones, the fracture length should be restricted to one-half the thickness of the producing interval, unless a fracture-height-containment technique is used. For example, assuming a producing interval of 50 ft, the etched, conductive fracture length, that is, the radius of the acidized fracture, should be 25 ft. The fracture acidizing treatment must be designed to equalize the injection and leakoff rates once the required acid penetration is obtained. This will optimize acid etching properties. An accurate estimate of the acid leakoff coefficient is required for that purpose and can be obtained from a pressure-decline analysis (from a previous acid fracturing treatment in the same reservoir). Treatments that require equalized injection and leakoff rates generally use HCl as the sole treating fluid. To achieve the desired radial fracture extension, acid injection rate should be above fracturing pressure until sufficient acid has been pumped. When the desired fracture extension is reached, injection should be continued but at a reduced rate corresponding to fracturing pressure. Continued injection at this intermediate pressure will keep the fracture open and permit the acid to create high



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conductivity over the radial length of the fracture. As pumping continues, leakoff will increase and injection pressure will approach pore pressure. The best results are obtained when perforations are restricted to a few holes in the center of the producing interval. 2.4 Maximizing The Injection Rate The first design criterion of most acid fracturing treatments is to maximize the injection rate (jobs in cool dolomites or using LCA fluids might be exceptions). Just as higher injection rates cause deeper penetration of the acid into the hydraulic fracture, the faster the acid moves within the fracture, the longer it takes for a given acid molecule to reach the fracture face and react with reservoir rock. This condition is true as long as the acid in the fracture is moving in laminar flow. Maximizing the acid fracturing injection rate first involves determining the maximum allowable wellhead treating pressure. This pressure will be dictated by the client or can be taken as some percentage of the maximum pressure rating of the surface equipment, and will correspond to a given injection rate (that is, a given friction pressure) through Eq. 1: Pw = σ min + Pe − Ph + Pf



(1)



Where: pw = maximum allowable wellhead pressure (psi) σmin = minimum in-situ stress (psi) pe = fracture net pressure (psi) ph = hydrostatic pressure (psi) pf = total friction pressure (psi). The fracture net pressure in acid fracturing is never larger than 250 psi (KGD or RADIAL fracture geometries). The maximum injection rate can be calculated for any acidizing fluid. Acid emulsions, ungelled acids and foamed ungelled acids exhibit high friction pressure in the tubulars which may limit the maximum injection rate, thereby limiting acid penetration into the fracture. Foams have another limiting factor, low hydrostatic pressure, which can also limit injection rates. 2.5 Optimizing Conductivity and Etched Fracture Length A unique feature of acid fracturing, as opposed to conventional fracturing with proppant, is that there is no theoretical limitation to the conductivity of an etched fracture. Increasing the conductivity of an acid-etched fracture is simply a matter of pumping more acid. The more acid pumped, the wider the etched width in a carbonate rock. Regardless of closure pressure and embedment strength of the reservoir, increasing the etched width always means increasing fracture conductivity DOWELL CONFIDENTIAL



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after closure. This is opposite to the permeability of a propped fracture which is related to proppant particle size and limited by proppant concentration. A dimensionless fracture conductivity (CfD) value 50 or greater means that the pressure drop in the etched fracture is negligible compared to the pressure drop in the reservoir, which is the ideal case. Since 3



FcD



kfwf wf = = kx a 12kx a



(2)



Where: xa = acid-etched fracture half-length (ft), kf = acid-etched fracture permeability (md), wf = after closure fracture width (in.) and k = reservoir permeability (md), the optimum fracture width after closure is well defined as soon as the maximum acid penetration (xa) is known: wf3 ≥ 600 k xa The stimulation ratio is the ratio of the stimulated production rate to the initial production rate at a given pressure differential between the wellbore and the reservoir boundary. For a given fracture length, the maximum stimulation ratio that can be achieved corresponds to the case of an infinite-conductivity fracture. A reservoir with an infinite-conductivity fracture (CfD ≥ 50) is known to behave as a homogeneous reservoir having an equivalent wellbore radius equal to one-half the acid-etched fracture half-length, with a stimulation skin equal to: Ss = ln( 2rw / x a )



(3)



Where: Ss = stimulation skin (dimensionless) rw = wellbore radius (ft). This relationship is valid as long as the fracture half-length is small compared to the drainage radius so that overall flow is approximately radial. This is normally the case since acid etch-length is rarely greater than 200 ft. This negative skin can be used in a Darcy flow equation to calculate the approximate reservoir productivity. 2.6 Effective Acid Concentration The effective acid concentration is the effective strength of the acid taking into account the nonacid components of the fluid. Gelled (or ungelled) 28% HCl has an effective acid concentration of 28% while 15% HCl has an effective acid concentration of 15%. However, an acid emulsion composed of 7 parts 28% HCl DOWELL CONFIDENTIAL



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and 3 parts diesel oil has an effective acid concentration of 19.6%. Similarly, a 70%quality foam having 15% HCl in its aqueous phase has an effective acid concentration of only 4.5%. Larger volumes of these fluids must be pumped in order to obtain a given fracture conductivity. If the acid is retarded, the retardation may compensate somewhat for the low effective acid concentration. Foam also has the additional drawback of providing low hydrostatic pressure. Except in areas with cleanup problems, acid systems other than foams may have better application. 2.7 Selecting Fluids for Deeper Acid Penetration To achieve fracture penetration, controlling the acid leakoff rate is imperative. Reasons for acid leakoff in acid fracturing are • natural fissures and fractures intersecting the hydraulic fracture • wormhole growth into the fracture walls • conventional fracturing fluid leakoff into porosity.



Decreasing Leakoff Through Natural Fissures Adequate control of acid leakoff into fissures is not simple. The best approach is to first bridge the inlet of the fissures with a fluid-loss additive such as a deformable 100-mesh resin, 100-mesh sand, or fine salt. The fluid-loss additive can serve as an induced (artificial) rock matrix and base for a wall-building fluid-loss additive. The fluid-loss additive used for bridging should contain particles that are smaller in diameter than the average fissure width but still large enough to support bridging. Estimates of the fissure-width and spacing are possible by the examination of formation cores or by logging techniques such as the Formation MicroScanner*, BHTV and SDT logs (Schlumberger Wireline and Testing). LCA fluids and viscous pads can also be used to decrease leakoff through natural fissures. The effectiveness of a second fluid-loss additive, the wall-building fluid-loss additive, in sealing the artificial matrix in the fissure inlets will be greatly enhanced if the individual particles will deform and adhere to each other. Thus the selection of the appropriate fluid-loss additive or fluid-loss additive blend is critical. The Fracturing Materials Manual  Additives, Matrix Materials Manual and the Dowell publication Fluid Loss Additives and Diverting Agents (TSL-2064) should be referenced before selecting the types of fluid-loss additives to use. Fluid-loss additives should be added to gelled fluid stages that precede and are interspersed with the acid stages. The presence of viscous fluid within the bridged fissure will also contribute to fluid-loss control.



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Decreasing Acid Leakoff Due to Wormholes There are several different methods of reducing acid leakoff due to wormholing. These are (from most to least efficient) • use LCA fluids •



fill existing wormholes with viscous, non-reactive fluids



•



viscosify the acid.



LCA fluids combine the advantages of having high viscosity plus a unique property of temporarily crosslinking at the interface between the acid and the formation. The crosslinked interface provides some of the desirable properties found in a conventional wall-building fluid-loss additive. Additional information on this process is provided in the Fracturing Materials Manual — Fluids. Viscosifying (gelling) the acid decreases the leakoff rate according to Darcy's law, that is, for a constant pressure differential, increasing the viscosity decreases the flow rate. This, in turn, decreases wormhole length. Some acid viscosifiers maintain a high viscosity while spending, but break when the acid is spent. Additional information on gelled acids is provided in the Fracturing Materials Manual — Fluids. The fracture acidizing treatment technique, DUOFRAC II, is designed to stop wormhole growth once growth has begun. The technique consists of initiating a fracture with a nonreactive pad of gelled fluid followed by alternating stages of acid and nonreactive pad. The first pad volume initiates a fracture for the first acid stage to follow. The first acid stage etches a portion of the fracture face and also creates leakoff wormholes that must be controlled. The second pad stage fills the initiated wormholes and prevents the second acid stage from entering the established wormholes. This acid stage will etch the next increment of fracture as well as create new wormholes in the next fracture increment. The process is repeated until the designed treatment volumes are depleted. The higher the viscosity of the nonreactive pad fluids, the more difficult it is for acid to displace the gelled fluid and resume wormhole growth.



Decreasing Leakoff Through Fracture Walls In proppant fracturing, the most common way to control fluid loss is to build an impermeable filter cake on the fracture walls. In acid fracturing, viscosity is much more effective for fluid-loss control. As an alternative, if the first stage of an acid fracturing treatment is a linear, inert fluid (with no wall-building characteristics) some leakoff control will be provided. The fluid will leak off into the native porosity of the fracture faces and will form a layer of viscous fluid in the first several inches of reservoir rock adjacent to the fracture. The viscous fluid bank will reduce acid leakoff better than a conventional polymer cake that does not offer any resistance to acid.



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The viscous fluid bank functions to control leakoff as a viscosity-controlled fluid. This approach to reducing leakoff is of benefit only in reservoirs where the resulting viscosity-controlled leakoff coefficient is smaller than the compressibility-controlled leakoff coefficient (for example, gas wells). Finding the correct information for this design may be difficult due to a lack of information about true leakoff viscosities of linear gels. Conventional American Petroleum Institute (API) fluid-loss tests are almost always interpreted in terms of their wall-building coefficient with the assumption that the leakoff viscosity is the viscosity of the base fluid. This design should not be used in wells with low bottomhole pressure because cleanup problems may occur. In this case, another technique can be used, resulting in a decrease of the apparent reservoir permeability along the fracture faces. This is achieved by emulsifying or foaming the treatment fluids. The leakoff is reduced as a result of the two-phase flow effects of the treating fluid leaking off into the reservoir rock adjacent to the fracture. Cleanup is expected to be easier, especially when the overflush stage incorporates large amounts of mutual solvents, surfactants and/or demulsifiers. 2.8 Determination of Leakoff Coefficients Laboratory studies of acid fracturing systems cannot derive leakoff coefficients representative of those that occur during acid fracturing when wormholing takes place. In the laboratory, a wormhole is induced and penetrates a small diameter core. The effect of leakoff through this induced wormhole is measured as a function of the cross-sectional area of the small diameter core. However, in the reservoir, wormhole density (the number of wormholes per unit of leakoff area) is thought to be considerably less. As a consequence, laboratory leakoff values calculated from artificially induced wormholes are (probably) greater than downhole conditions. These laboratory tests are, however, useful to compare the relative leakoff data and etch characteristics of the various acid systems. The following methodology has been derived using relative leakoff data from the laboratory. 2.8.1 Methodology 1.



Estimate the apparent reservoir permeability (ka) during the acid stages. Based on the considerations discussed previously (Acid Leakoff), the matrix permeability (kr) of the reservoir is estimated to be approximately five percent of the total effective permeability of a fissured reservoir.



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The apparent permeability can be estimated along the following guidelines. • If the reservoir is not fissured, ka = kr •



If the reservoir is fissured, and if √ no fluid-loss additive is used, ka = kr √ a fluid-loss additive is used in linear pads before each acid stage: k ka = r 3 √ a fluid-loss additive is used in crosslinked pads before all acid stages, or k LCA fluids are the acid system, ka = r 10



2.



In Fig. 7, Table 3, Table 4, and Table 5, the permeability to consider is the apparent permeability and the temperature is the average temperature in the fracture (Ta).



Fig. 7. Viscosity of fresh water versus temperature.



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Table 3. Total Minimum Leakoff Coefficients versus Temperature and Permeability Comparative values for Ctmin can be obtained using the table below. The numbers shown were compiled from Cw and spurt values for crosslinked fluids provided in the Fracturing Materials Manual — Fluids . Since these are estimated values, extrapolations for other permeabilities and temperatures can be made. Total Leak-Off Coefficient (Ctmin = ft/min½) Apparent Permeability



Temperature °F °C



100 38



150 66



200 93



250 121



10



0.0025



0.0030



0.0040



0.0055



(md)



3. Determine the viscosity, compressibility coefficient (Cvc) for water, using of the apparent permeability and the other reservoir data. Water viscosity taken at Ta is used to estimate the maximum leakoff coefficient, Ctmax, of an inert fluid in the studied reservoir (that is, the poorest control of fluid loss). Eq. 3, Eq. 4, and Eq. 5 in Appendix E — Fluid Loss can be used instead of the FracCADE software to obtain the Cvc for water, that is, Ctmax. Similar results should be obtained providing that an average fracture net pressure of 250 psi is considered, and that identical compressibility and saturation values for rock, oil, gas and water are used. 4. Determine Ctmin, the minimum leak-off coefficient for an inert fluid (best leakoff control) from Table 3. 5. The value for Ctmin should not be greater than that of Ctmax. If it is, review the reservoir data and correct. When the values are confirmed, then the total coefficient values CtF for all fluids will be equal to Ctmax. 6. Determine the scale of efficiency (SFb) for controlling leakoff using Table 4.



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Table 4. Scale Factor Base Values (SFb) This table below, based on comparative laboratory test results, presents the degree of leakoff control expressed as values between zero (best control) and eleven (poorest control) for reactive and nonreactive fluids. Limestone >250/121 °F/°C ≤100/38 ≤150/66 ≤200/93 ≤250/121 Fluid Dolomite >350/177 °F/°C ≤200/93 ≤250/121 ≤300/149 ≤350/177 Ungelled Acid + F98 NA NA NA 11 10 Ungelled Acid 8 11 10 9 8 DGA*200, 300, and 400 5 8 7 6 5 SXE fluids NA NA NA 8 7 LCA fluids 3 4 4 3 3 Water ----------------------------------------------8-------------------------------Linear Pad ----------------------------------------------3-------------------------------Crosslinked Pad ----------------------------------------------0-------------------------------NOTE a) For ungelled acid, SFb should be decreased by a value of one for each 7% decrease in acid concentration below 28%. b) For the other acid systems, viscosity tends to dampen decreases in acid concentration. c) SFb values for organic acid are given the same values as used with ungelled 15% HCI + F98. d) For all fluids:  Decrease SFb by one if energized,  Decrease SFb by two if foamed. 7. Using the previously determined SFb values, corrected scale factors, (SFc), should now be derived according to the guidelines in Table 5. Corrections are necessary to account for the effects the different fluid systems have on each other.



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Table 5. Scale Factor Corrections These corrections are necessary to account for the effects the different fluid systems have on each other. REACTIVE FLUIDS THE MINIMUM SFc VALUE IS ONE a) Decrease SFb by one when the apparent permeability is less than 1 md; and again by one for each order of magnitude ten decrease of the apparent permeability. This is reflective of limited wormhole propagation due to small pore radii. b) After the first pad of linear gel, decrease SFb by two to account for viscosity controlled leak-off. c) After the first pad of crosslinked gel, decrease SFb by one. Perforation of the polymer cake will be rapid. d) Decrease SFb by two after other pads, linear or crosslinked. This value is a tradeoff between wormhole filling at the fracture inlet where crosslinked fluid is better and on new fracture face at the fracture tip where linear fluid is better. NONREACTIVE FLUIDS  THE MINIMUM SFc VALUE IS ZERO a) Increase SFb by one when the nonreactive fluid follows an acid stage having a SFb value between three and six, b) Increase SFb by two when the non-reactive fluid follows an acid stage having a SFb value between six and nine, c) Increase SFb by three when the non-reactive fluid follows an acid stage having a SFb value of greater than nine. This accounts for the spurt that takes place when wormholes are filled by the gelled non-reactive fluid. 8. The final total leakoff coefficient (CtF) of the fluid being considered is determined using Eq. 4. CtF = Ct min + 0.125 × (Ct max − Ct min ) × SFc Where: CtF = total leakoff coefficient (ft/min½ ), Ctmin = minimum leakoff coefficient (ft/min½), and Ctmax = maximum leakoff coefficient (ft/min½). When using Eq. 4, note that for: SFc = 0, CtF = Ctmin. (case for a crosslinked pad), SFc = 8, CtF = Ctmax. (case for a plain-water pad), DOWELL CONFIDENTIAL



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Note also that some stages can have larger leakoff coefficients (even poorer fluid leakoff control) than plain water if their SFc is greater than 8. CtF values determined in the above manner must be used in conjunction with zero spurt and with leakoff coefficient flag on TOTAL in the Fluid Editor of FracCADE. These corrections are necessary to account for the effects the different fluid systems have on each other. 2.8.2 Example Calculation Reservoir Parameters: • fissured dolomite oil reservoir •



permeability 10 md, porosity 12%



•



oil viscosity = 0.6 cp



•



total compressibility = 5 X 10-5 psi-1



•



bottomhole static pressure = 1770 psi



•



minimum in-situ stress = 5120 psi



•



fracture net pressure = 0 psi



•



average temperature in the fracture = 200°F



Pumping schedule (using DUOFRAC II system): 1) Crosslinked pad with fluid-loss additive 2) 20% HCl 3) Crosslinked pad 4) 20% HCl 5) Water overflush 1.



Estimate the apparent permeability (ka) of the reservoir during the acid stages: Fissured reservoir, but a crosslinked pad with fluid-loss additive is used: ka = kr /10 = 1 md



2.



Verify ka and Ta. ka = 1 md, Ta = 200°F



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Determine Cvc for water at Ta = 200°F. Water viscosity at 200°F = 0.3 cp  1 × ( 5120 − 1770 + 0 ) × 0.12  Cν = 1.48 × 10 − 3   0.3 



1/ 2



= 0.0542 ft / min 1/ 2 Cc = 119 . × 10



−3



 1 × 5 × 10 − 5 × 0.12  ( 5120 − 1770 + 0)   0.6  



1/ 2



= 0.0126 ft / min 1/ 2 Cνc =



2 × 0.0542 × 0.0126



[



0.0542 + (0.0542) 2 + 4( 0.0126 ) 2



]



1/ 2



Cνc = 0.0120 ft / min 1/ 2 [Note that Cvc for water in the case of no control of leakoff into natural fissures (ka = kr= 10 md) would be equal to 0.0379 ft/min½, that is, the Cvc above times: 10 ]. 4. Determine the minimum leak-off coefficient for a nonreactive pad. At Ta = 200°F and ka = 1 md and using , Ctmin = 0.0020 ft/min½ 5. Verify that Ctmin is less that Ctmax. Ctmin = 0.0020 ft/min½, Ctmax = 0.0120 ft/min½. 6. Determine the SFb values using Table 4. See pumping schedule. a. Crosslinked pads. SFb for crosslinked pad = 0 b. 20% HCl, 200°F. concentration)



SFb for 20% HCl = 7 (Adjusted 8 - 1 = 7 for acid



c. Water Overflush. SFb for Water Overflush = 8 7. Determine SFc values using Table 5. Follow the pumping schedule. a. Crosslinked pad. SFc = 0 (No correction.) b. 20% HCl. SFc = 6 (Corrected 7 - 1, Acid follows crosslinked pad.) c. Crosslinked pad. SFc = 2 (Corrected 0 + 2, second pad stage follows the first acid stage.) d. 20% HCl. SFc = 5 (Corrected 7 - 2, Second stage of acid follows second stage of pad.) DOWELL CONFIDENTIAL



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e. Water Overflush. SFc = 9 (Corrected 8 + 1, follows second acid stage having an SFc of 5.) 8. Determine the CtF for each fluid using . a. Crosslinked pad (first one) SFc = 0, CtF = 0.0020 ft/min½ b. 20% HCl (first stage) SFc = 6, CtF = 0.0095 ft/min½ c. Crosslinked pad (second one) SFc = 2, CtF = 0.0045 ft/min½ d. 20% HCl (second stage) SFc = 5, CtF = 0.01075 ft/min½ e. Water overflush SFc = 9, CtF = 0.01325 ft/min½ 2.8.3 Notes When estimating CtF for any stage of any fluid for a particular treatment, everybody has to exercise their own judgment. For instance, not using any fluid-loss agent in a second pad stage obviously should impair the leakoff control abilities of the considered pad and following stages. A good indication on how much this effect would be is given by recalculating the Ctmin and Ctmax with ka = kr. However, this loss of efficiency only concerns the tip of the fracture; therefore, CtF have to be worked out as averages between the fully controlled case (with ka = kr/10) and the fully uncontrolled one (with ka = kr). The “wormhole perimeter” coefficient in the acid simulator screen of FracCADE (SETUP option REGULAR) is a research tool which must not be used when designing actual jobs and using the method of determination of leakoff coefficients described above. The default value of 0 in the FracCADE software actually means that this coefficient is not considered in the estimation of the leakoff volumes by the simulator. Any other values would have to be used in conjunction with actual leakoff data generated in the laboratory on one-in. diameter limestone cores. 2.9 Cooldown Temperature controls both the diffusion and the surface-reaction rates. At high temperatures limestones and dolomites react very rapidly with hydrochloric acid; so rapidly, that acid-etching of the fracture may be limited to only a few feet. If acid fracturing is the only viable means of fracture stimulation, cool-down must be considered. The best fluids for cooldown are high-leakoff fluids. An example would be a waterbase fluid containing a friction reducer. Obviously, the larger the volume of cold fluid invading the formation and the higher the injection rate, the lower the cooldown temperature in the fracture and the longer it takes the reservoir temperature to rebound and heat the fracture to the original bottomhole static temperature when leakoff stops. The most important aspect of fracture cooldown is the invasion of the primary porosity of the reservoir rock adjacent to the fracture faces.



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Injecting large amounts of a cold fluid into a pattern of natural fissures will not succeed at notably decreasing the temperature of the rock between the fissures. Therefore, the first requirement in a fissured reservoir is to consider limiting leak-off into the fissures. Once the leakoff to fissures has been limited, cooldown can be initiated. Temperature models show that the temperature in a fracture induced by a low-efficiency fluid such as water has a linear profile. At any time during the propagation of the fracture, the temperature at any distance from the wellbore can be calculated using Eq. 5.



[T ( X ) − Tw ] = [Tbhs − Tw ] x



Where



xf



(5)



T(X) = fluid temperature in the fracture at distance (X) from the wellbore (°F [°C]) Tw = wellbore temperature at the perforations (°F [°C]) X = distance from the wellbore (ft) Tbhs = bottomhole static temperature (°F [°C]) xf = hydraulic fracture half-length (ft). In most cases, Tw is reached rapidly and levels-off at a value slightly above the surface temperature of the cooldown fluid (normally from 10° to 30°F [5° to 15°C] above the surface temperature of the cooldown fluid). This depends on the injection rate and the volume injected. Circulating the wellbore with cold water before an acid fracturing treatment (before initiating formation cooldown) will allow for more confidence when estimating Tw.



Calculating Cooldown A simple method of designing a cooldown treatment is: 1.



Determine the maximum acid penetration (xa) at a cooldown temperature (Ta) using the FracCADE software.



2.



Determine the required hydraulic fracture half-length at the end of cooldown in order to obtain (Ta) at the distance (xa) from the wellbore (Eq. 6). x f = xa



Tbhs − Tw Ta − Tw



(6)



Where: xa = acid-etched fracture half-length (ft) Ta = fluid temperature at distance (xa) from the wellbore (°F [°C]). 3.



Run the FracCADE software again to determine the required cooldown pad volume to achieve (xf) before acid injection.



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2.10 Retarded Acid A retarded acid is an acid with a reduced reaction rate. The degree of retardation is defined by a retardation factor. The retardation factor for plain HCl at any concentration is one. Therefore, a retarded acid has a retardation factor greater than one. Most retarded acids are modifications of HCl. When compared to unretarded HCl, retarded acid penetrates more deeply into the hydraulic fracture thereby increasing acid-etched length. If all other factors remain unchanged, fracture width is decreased because the acid has been altered so that it can penetrate deeper into the hydraulic fracture before becoming spent. The retardation factor is derived by comparing the overall reaction rate of a retarded acid to the overall reaction rate of nonretarded hydrochloric acid. Specifically, it is the ratio of the slope of the spending profile for the retarded acid to the slope of the spending profile for nonretarded HCl under an identical set of conditions. provides retardation factors for various acid systems and guidelines for modifying the retardation factors.



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Table 6. Retardation Factor Selection Guidelines The values shown are guidelines for selecting retardation factors (RF). Note that small deviations from the retardation factor value for plain HCl will have large effect on the acid penetration calculated by the FracCADE software. 1. Base Values RF a. HCl, DGA and LCA systems



1.0



b. Acid-external emulsions (DAD)



2.0



c. Surfactant retarded with F98



2.0



d. Organic acids (formic or acetic)



4.0



e. Acid-internal emulsions (SXE)



10.0



2. Modifications to the Base Values Add to RF a. If linear pad before acid stage



0.5



b. If crosslinked pad before acid stage



1.0



c. If acid stage energized with CO2



0.5



d. If acid stage foamed with CO2



1.0



e. If acid stage foamed with N2 only



0.5



Determining the Retardation Factor by Dynamic Testing The retardation factor must be measured under dynamic conditions. Under static conditions, for example, the spending times of gelled acids are extended (Fig. 8). The gelled acid only appears retarded. Under dynamic conditions, the spending time of Gelled Acid A is the same as 15% HCl (Fig. 9). Under static conditions, Gelled Acid A appears retarded because its viscosity prevents immediate dispersion of acid reaction products (CO2, CaCl2 and water). These reaction products form a temporary barrier between the carbonate rock and live acid. Under dynamic conditions, these reaction products are swept away and the retardation factor of one is maintained. This does not imply that every acid containing a surfactant is retarded nor is every gelled acid not retarded. Each acid solution must be tested under the same dynamic conditions before meaningful comparisons can be made. It is valid, in a narrow sense, to consider gelled acids that utilize no retarding mechanism to be retarded. The viscosity of a gelled acid will provide a wider fracture than ungelled acid (and sometimes will switch flow conditions from turbulent to laminar). The viscosified acid will penetrate deeper into the reservoir before DOWELL CONFIDENTIAL



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convection causes contact with the fracture faces. accounts for these factors.



Section 900 May 1998 Page 35 of 37 The FracCADE software



Fig. 8 and Fig. 9 compare the spending time of acid and limestone in static tests versus the retardation factor of the same acid systems under dynamic conditions. These include acid concentration, temperature, pressure, rheology, type of carbonate rock used, fluid saturation of the rock, injection rate unit of fracture height and initial fracture width. Static tests are of little value when determining the behavior of an acid system in a reservoir.



Fig. 8. Spending time versus HCl concentration at static conditions. Note that Gelled Acid A and Surfactant Retarded Acid B appear retarded.



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Fig. 9. Temperature versus retardation factor at dynamic test conditions. 2.11 Viscous Fingering Viscous fingering is a physical phenomenon that increases acid penetration. Fingering occurs when a viscous fluid is displaced by a less viscous fluid; the interface of the two fluids being very unstable. Pumping acid behind a more viscous pad will cause multiple fingers of acid to quickly extend into the pad. Acid fingering has three positive effects. 1. The overall velocity of the acid in the fracture is increased slightly by the fingering behavior. 2. The acid-etched length is increased. 3. The acid leakoff area is decreased. A DUOFRAC II treatment will also experience viscous fingering, but this fingering is probably secondary to the original purpose of the DUOFRAC II procedure. The primary intent is to increase hydraulic fracture width and to provide acid leakoff control.



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The FracCADE software does not model viscous fingering behavior, rather accounting for fluid displacement in a fracture using plug-flow calculations. Modeling of viscous fingering would require determination of the number, height and width of acid fingers in the fractures and accurate vertical permeability measurements. The value for each of these properties is highly subjective. 2.12 Summary of Treatment Design Fundamentals for Acid Fracturing Fluid selection is relatively easy if the objective of the acid fracturing treatment is to maximize the acid penetration. • Always use the maximum true acid concentration. •



Always consider acid leakoff. Consider the DUOFRAC II process or low-leakoff systems or both.



•



Select pad fluids and acid systems that will create deep flow channels within the fracture.



•



Temperature (ranges below are for chalks and limestones  add 100°F for dolomites): − Less than 100°F (38°C): Use straight acid at lowest injection rate (though above fracturing rate) to compensate for very slow reaction rate. − 100° to 150°F (38° to 66°C): Candidate acid systems are gelled acids and low-leakoff acids. − 150° to 200°F (66° to 93°C): Candidate systems are high-temperature gelled acids or low-leakoff acids. − 200° to 250°F (93° to 121°C): Candidate systems are acid-in-oil emulsions and high temperature gelled acids.



•



− Greater than 250°F (121°C): Consider cooldown procedures or retarded acids. Retarded acid can increase etched fracture penetration.



Energizing with CO2 or N2 may be necessary in wells where cleanup problems are anticipated. Foaming is not recommended where deep penetration is required because the effective acid concentration is reduced significantly and injection rate is limited.



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Section 1000 May 1998 Page 1 of 43



HORIZONTAL WELLS 1 Introductory Summary............................................................................................................. 4 1.1 Candidate Reservoirs for Horizontal Wells .......................................................................... 4 1.1.1 Naturally-Fractured Reservoirs................................................................................... 4 1.1.2 Matrix-Permeability Reservoirs................................................................................... 4 1.1.2.1 Vertical Permeability ........................................................................................ 5 1.1.2.2 Skin Damage ................................................................................................... 6 1.2 Fracture Performance and Wellbore Orientation ................................................................. 7 2 Fracture Orientation ................................................................................................................ 8 3 Fractured Horizontal Well Performance............................................................................... 10 3.1 Longitudinal Fracture ......................................................................................................... 10 3.2 Orthogonal Fractures ......................................................................................................... 11 3.3 Choke Skin Effect............................................................................................................... 13 3.3.1 Fracture Reorientation — Choke Effect.................................................................... 14 3.4 Coning Effects.................................................................................................................... 15 3.4.1 Comparison of Fractured and Nonfractured Reservoir............................................. 15 3.4.2 Effect of the Distance From the Fracture to the Water Zone.................................... 15 4 Rock Mechanical Properties ................................................................................................. 17 4.1 Openhole Wellbore Stability............................................................................................... 17 4.2 Shear Failure ..................................................................................................................... 18 4.3 Tensile Failure ................................................................................................................... 18 4.4 Matrix Collapse .................................................................................................................. 18 4.5 Cased-Hole Wellbore Stability ........................................................................................... 19 4.6 Stress and Deformation Analysis ....................................................................................... 20 5 Fracture Initiation And Propagation..................................................................................... 20 5.1 Initiation Pressure .............................................................................................................. 20 5.2 Fracture Initiation ............................................................................................................... 21



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5.3 Fracture Propagation..........................................................................................................23 5.4 Longitudinal Fractures ........................................................................................................23 5.5 Angled Fractures ................................................................................................................24 5.6 Transverse Fractures .........................................................................................................25 5.7 Controlling Fracture Reorientation......................................................................................26 6 Perforating ..............................................................................................................................27 7 Treatment Design ...................................................................................................................29 7.1 Net Present Value Analysis ................................................................................................29 7.1.1 Calculating the NPV of Orthogonal Fractures ...........................................................29 7.1.2 Horizontal Well Production Prediction .......................................................................31 7.2 Fracture Height...................................................................................................................34 7.3 Fracture Orientation ...........................................................................................................34 7.4 Fracture Length and Conductivity.......................................................................................34 7.5 Pump Rate..........................................................................................................................34 7.6 Fracturing Fluid Selection...................................................................................................34 7.7 Proppant Selection .............................................................................................................35 7.7.1 Mesh Range..............................................................................................................35 7.7.2 Proppant Type...........................................................................................................35 7.7.3 Proppant Concentration ............................................................................................35 8 Execution ................................................................................................................................35 8.1 Perforating ..........................................................................................................................35 8.1.1 When to Perforate .....................................................................................................36 8.2 Wellbore Isolation Between Fractures................................................................................36 8.2.1 Isolation Using Mechanical Tools..............................................................................37 8.2.2 Isolation Using Proppant Plugs .................................................................................37 8.2.2.1 Intentional Screenout .....................................................................................37 8.2.2.2 Multidensity/Multimesh Proppant ...................................................................38 8.2.3 Isolation Using Viscous Plugs ...................................................................................38 8.2.4 Wellbore Isolation in an Openhole Completion .........................................................39 8.3 Flowback ............................................................................................................................39 DOWELL CONFIDENTIAL



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9 Overview of the Horizontal Well Treatment-Design Procedure ......................................... 40 10 Case History ......................................................................................................................... 41 FIGURES Fig. 1. Fig. 2. Fig. 3. Fig. 4. Fig. 5.



Productivity index ratios for horizontal versus vertical wells. ............................................ 6 A longitudinal fracture. ...................................................................................................... 8 An orthogonal fracture. ..................................................................................................... 9 A fracture propagating at an angle to the wellbore. .......................................................... 9 Productivity index ratios of vertical well/vertical fracture and horizontal well with a longitudinal fracture......................................................................................................... 10 Fig. 6. NPV analysis for a vertical well. ...................................................................................... 12 Fig. 7. NPV analysis for one orthogonal fracture. ...................................................................... 12 Fig. 8. Water breakthrough time versus the position of the fracture with respect to the oil/water contact. ....................................................................................................... 16 Fig. 9. Production rate versus water-cut. ................................................................................... 16 Fig. 10. Fracture conductivity versus water-cut. ........................................................................ 17 Fig. 11. Mohr failure envelope for matrix collapse. .................................................................... 18 Fig. 12. Stress distribution around a perforation. ....................................................................... 20 Fig. 13. Initiation pressure as a function of α and the borehole inclination. ............................... 21 Fig. 14. Horizontal well configuration in the in-situ stress field................................................... 21 Fig. 15. Initiation points and fracture orientation on the borehole. ............................................. 22 Fig. 16. Fracture initiation pressure. .......................................................................................... 22 Fig. 17. The effect of distance between collinear fractures on maximum fracture width............ 24 Fig. 18. Fracture rotation angle versus spacing......................................................................... 25 Fig. 19. Width and excess pressure as a function of spacing for parallel, transverse and radial fractures........................................................................................................ 26 Fig. 20. Radius of fracture reorientation as a function of the ratio between the maximum and minimum horizontal stresses. ................................................................................. 27 Fig. 21. Critical distance between perforation versus well orientation. ...................................... 28 Fig. 22. Single phase flow .......................................................................................................... 33 Fig. 23. NPV analysis of the number of orthogonal fractures..................................................... 42 Fig. 24. Actual versus predicted fluid production. ...................................................................... 43 TABLES Table 1. Table 2. Table 3. Table 4.



Performance Comparison Of Vertical And Horizontal Wells With Fractures................ 13 Pseudoskin Factor Correlation Contstants................................................................... 32 Overview of Fracture Treatment Design Considerations for Horizontal Wells ............. 40 Stress Measurement Techniques ................................................................................ 41



1 Introductory Summary Successful hydraulic fracturing of wells with horizontal or deviated wellbores depends upon a number of factors. The most important factors are DOWELL CONFIDENTIAL



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•



The fractured well should be a viable economic alternative to a fractured vertical well or wells.



•



Stability risks, such as wellbore or casing collapse during drilling, stimulation or production, are understood and are considered acceptable.



•



Cementing or completion or both is satisfactorily accomplished.



•



A decision to create a single hydraulic fracture, or to create multiple fractures simultaneously or in stages has been made.



Horizontal wells that are candidates for hydraulic fracturing are usually those with low natural permeability, unfavorable permeability anisotropy and no natural fractures. 1.1 Candidate Reservoirs for Horizontal Wells The most prevalent economic incentive is the increased productivity of a horizontal well as opposed to a fractured vertical well. In many cases, horizontal wells are drilled specifically to minimize water and gas coning rather than to increase oil or gas production. 1.1.1 Naturally-Fractured Reservoirs The benefits of a horizontal well (versus a vertical well) in a naturally-fractured reservoir are • an increased number of natural fractures are intersected (production is increased) •



drainage area is increased



•



the need for hydraulic fracturing is eliminated.



The most successful horizontal wells (and the majority of horizontal wells) are completed in naturally-fractured reservoirs. 1.1.2 Matrix-Permeability Reservoirs The benefits of a horizontal well (versus a vertical well) in a matrix permeability reservoir are • reservoir contact with the wellbore is increased (increased productivity index) •



linear flow in the reservoir (reduced water and gas coning)



•



drainage area is increased.



A productivity increase in a matrix permeability reservoirs is a result of an increase in reservoir area (length) in contact with the wellbore. The reservoir contact in a vertical well is limited to the height of the reservoir. The most benefit from this approach is in thin reservoirs or in reservoirs with a thin oil column. In the case of a thin oil column, a horizontal well has the additional advantage of increased DOWELL CONFIDENTIAL



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Section 1000 May 1998 Page 5 of 43



production with less drawdown, that in many cases will reduce or eliminate water or gas coning. There is less tendency for water or gas coning to occur in a horizontal well because a horizontal well requires a much smaller pressure drawdown to produce at the same rate as a vertical well. The pressure gradient from the horizontal wellbore to the drainage radius is almost linear as opposed to a vertical well where there is a log-linear pressure gradient from the wellbore to the drainage radius. This results in a steady gas dip or water crest over the producing length of the horizontal wellbore rather than a cone flowing to a single point source (which accelerates water or gas coning) as in a vertical well. A productivity increase is not simply equal to the ratio of the length of the horizontal well to the thickness of the reservoir. Vertical permeability and skin damage are limiting factors to well performance. 1.1.2.1 Vertical Permeability The negative impact of low vertical permeability compared to horizontal permeability is illustrated in where β = (kh/kv)½. Fig. 1 shows a comparison of productivity index (PI) ratios (q/∆p) for three situations; common anisotropy (β = 3), complete isotropy (β = 1), and highly favorable vertical anisotropy (β = 0.25). The comparison is made for three net heights; 20 ft, 100 ft, and 200 ft. For this illustration, the drainage radius is 0.326 ft (7.875-in. borehole). Fig. 1 indicates that the value of β is crucial. If β is typical (≈ 3 for common anisotropy), the PI ratio will be small. Conversely, if β is small, as would be the case in formations with massive natural vertical fissures, then the PI ratio can be extremely large and a horizontal well is an obvious choice.



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Fig. 1. Productivity index ratios for horizontal versus vertical wells. Fig. 1 also indicates that the reservoir thickness is important. Horizontal wells are less attractive for thicker formations and the PI ratios decrease as the formation becomes thicker. The majority of horizontal wells are drilled in formations less than 150-ft thick. Inverted high-angle wells, stepped wells and hydraulic fracturing (not a simple solution) can offset low vertical permeability. Water and gas coning can be less readily controlled in wells with high vertical permeability. The extreme case is when small faults or natural fractures are present in the formation. 1.1.2.2 Skin Damage The presence of skin damage in a horizontal well can be determined by type-curve matching or with the STAR* software. Most horizontal wells drilled in matrix permeability are damaged. Cuttings that are ground into a fine paste by the movement of the drill string in the horizontal wellbore will plug the pore throats in the matrix close to the wellbore. This is more of a problem in horizontal wells than vertical wells because the drill string (in a horizontal wellbore) lies on the low side of the wellbore and PDC bits (often used to drill a horizontal well) produce fine cuttings (as opposed to roller bits that produce coarse cuttings). *



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1.2 Fracture Performance and Wellbore Orientation The behavior and performance of a fracture propagating from a horizontal wellbore is a result of the wellbore orientation with respect to the principal stresses in the formation.



Wellbore in the Direction of the Minimum Horizontal Stress (σ σHmin) • Production from the fracture is reduced by limited contact with the wellbore because of the choke skin effect (Sch)c. •



Multiple orthogonal fractures are required to maximize the productivity of the well in terms of net present value (NPV).



•



Higher breakdown pressure than a vertical well.



•



A short perforated interval (less than four times the wellbore diameter) is required to prevent the creation of multiple fractures from the same interval.



•



Fracture spacing must exceed one-half the fracture half-length to prevent interference (reduced fracture width, increased net pressure and rotation).



Wellbore in the Direction of the Maximum Horizontal Stress (σ σHmax) • Productivity from the fracture is not choked by limited contact with the wellbore. •



The equivalent of a single fracture can be created along the wellbore.



•



Lower breakdown pressure than a vertical well.



•



Little interference between fractures.



•



Length of the perforated interval may not be so critical.



Wellbore at an Angle Between σHmin and σHmax • Production is limited by the effects of choke skin effect and additional choke effect (Sfs)c. •



Multiple fractures are reoriented at some point away from the fracture.



•



Fractures have nonidentical wings.



•



Higher friction pressure and possible proppant bridging because of fracture reorientation.



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2 Fracture Orientation The orientation of hydraulic fractures in a horizontal well depends on the magnitude and orientation of in-situ stresses. Because of the stresses being concentrated near the wellbore, the direction in which a fracture initiates at the wellbore will seldom be the direction in which it will ultimately propagate, which is perpendicular to the direction of the minimum principal stress, or along a dominant natural fracture. Therefore, in many cases, hydraulic fractures may not be planar features. A fracture which initiates and then propagates longitudinally along the axis of a wellbore will do so from a number of perforations at the wellbore (Fig. 2). Therefore, it is reasonable to presume that the pressure drop, while treating or producing the well, will be similar to that of a vertical well.



Fig. 2. A longitudinal fracture. A fracture which initiates or propagates or both, at an angle to the wellbore will be in communication with fewer perforations. When the hydraulic fractures are orthogonal to the direction of the wellbore (Fig. 3), the inefficient contact between the fracture and the well can be quantified by introducing a choke skin effect (Eq. 1). ( Sch )c =



kh [1n(h / 2rw ) − π / 2] kfw



Where: (Sch)c = choke skin effect (dimensionless) kh = horizontal permeability (md) kfw = fracture conductivity (md.ft) h = net reservoir thickness (ft) rw = wellbore radius (in.).



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Fig. 3. An orthogonal fracture. Fractures which propagate in a direction between the two extremes will have a much more complicated geometric shape (Fig. 4). A fracture may initiate in a longitudinal direction and then reorientate so that it grows perpendicular to the minimum principal stress, once is has grown away from the influence of the wellbore and the completion. In this case, the maximum fracture width may not occur at the wellbore and may not vary uniformly along the length of the fracture. The reorientation of the fracture and its nonuniform geometry will act in some degree to limit production from the fracture.



Fig. 4. A fracture propagating at an angle to the wellbore.



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3 Fractured Horizontal Well Performance When planning to fracture an existing horizontal well or to drill a well which will require fracturing, a careful study must be made to determine the orientation of the fracture or fractures and how this may impact any increased productivity. In many cases, fracturing a horizontal well will further delay the onset of water or gas coning. 3.1 Longitudinal Fracture A comparison of a vertical fractured well with a longitudinally fractured horizontal well is shown in Fig. 5.



Fig. 5. Productivity index ratios of vertical well/vertical fracture and horizontal well with a longitudinal fracture. Productivity index ratios of vertical well/vertical fracture and horizontal well with a longitudinal fracture. This comparison is for a fully penetrating fracture (that is, 2xf = L) and a fractured vertical well with a fracture half-length equal to xf. The CfD values for the fractured well are graphed along the abscissa. This is a logarithmic axis, accentuating small CfD values. Finally, several L/h ratios (the horizontal well length divided by the reservoir thickness, 10, 20, and 30 ft) are plotted. Fig. 5 shows that for large conductivity fractures (CfD > 20) or small L/h ratios (< 5), the ratio of the productivity index of a horizontal well and the productivity index of a vertical well



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[(PI)horizontal /(PI)vertical ] is approximately equal to 1. Therefore, a horizontal well drilled in the direction of the maximum horizontal stress axis would not be appropriate. Given a minimum requirement of [(PI)horizontal /(PI)vertical] > 2, a horizontal well drilled so the hydraulic fracture will propagate longitudinally would be advantageous, if CfD < 2.5 and L/h = 20. 3.2 Orthogonal Fractures Hydraulic fractures which propagate orthogonally from the wellbore have two distinct possible advantages over longitudinal fractures, although their performance is reduced due to choke skin effect. These are: 1.



Multiple parallel fractures are possible.



2.



A larger drainage area can be affected.



The location of a horizontal wellbore within the reservoir is the key factor in determining the benefits to be gained by increasing the potential drainage area. In some cases, the location of the wellbore within the reservoir may limit the potential of the well. In the case of orthogonal fractures, the FracNPV* module in the FracCADE* software can be used to optimize the number and size of hydraulic fractures. The analysis must incorporate the choke skin effect. For each orthogonal fracture, the drainage area is divided equally and performance (including the choke skin effect) over time is calculated. To calculate the skin effect, some value of the fracture conductivity must be assumed. The NPV of each fracture is of particular importance to optimize the number of fractures which are required. It must include, as a fixed cost, a fraction (based on the number of orthogonal fractures that are planned) of the additional cost of drilling a horizontal well. The sum of the NPVs must be larger than the NPV of a hydraulically fractured vertical well. This is illustrated in Fig.6 and Fig.7. Note that for an individual orthogonal fracture, the optimum fracture length is 800 ft and the maximum NPV is $1,320,000 compared to 1400 ft and $4,500,000 in the case of a vertical fracture in a vertical well in the same reservoir. For this reason, many horizontal wells that are candidates for fracturing require 5 to 10 orthogonal fractures placed along the wellbore to equal the NPV of a massive hydraulically fractured vertical well. The best candidate reservoirs are usually relatively thin with low permeability.



*



Mark of Schlumberger



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Fig. 6. NPV analysis for a vertical well.



Fig. 7. NPV analysis for one orthogonal fracture. DOWELL CONFIDENTIAL



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3.3 Choke Skin Effect To demonstrate the impact of the choke skin effect, the expected flow rates from a vertical well with a vertical fracture and a horizontal well with a single orthogonal vertical fracture are calculated. Two cases are considered — a reservoir with 1-md permeability and another with 0.1-md. Well parameters for both cases are listed below. h =100 ft rw =4.872 in. w =0.25 in. kf =24,000 md



µ =1 cp xf =500 ft p - pwf =1000 psi xs =10 ft ws =0.5w kfs =0.5kf CfD =10-4 φ=15% ct =10-5 psi-1 B =1.1 res bbl/STB The choke skin effect is calculated using Eq. 1. The production is then calculated and compared after 180 days. The results are shown in Table 1.



Table 1. Performance Comparison Of Vertical And Horizontal Wells With Fractures k(md)



Vertical Well Vertical Fracture



Horizontal Well Vertical Fracture



1.0



165 BOPD



141 BOPD



0.1



34 BOPD



30 BOPD



As the results clearly show, the reduction in flow rate due to the choke skin effect is greater when the kh product is larger. However, in a low-permeability reservoir, with a small kh and small choke skin effect, the production may not justify the additional cost of drilling the horizontal well section. Therefore, each well must be considered on a case-by-case basis in terms of NPV and the number of orthogonal fractures required to maximize economic productivity.



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3.3.1 Fracture Reorientation — Choke Effect The reorientation of the fracture away from near wellbore stresses may result in additional choke which may be defined in terms of damaged proppant permeability or reduction in width of the hydraulic fracture. πx s k ( S fs )c = (2) w s k fs Where: (Sfs)c = additional choke effect (dimensionless) xs = length of the damaged interval (ft) k = permeability (md) ws = reduced width (ft)



kfs = damaged proppant permeability (md). To illustrate the potential magnitude and effect of this choke, consider the following examples using the variables listed above. For the 1.0-md case, applying Eq. 2, (Sfs)c = 0.125. For the 0.1-md case, applying Eq. 2, (Sfs)c = 0.0125. If the hydraulic fracture or fractures will not be propagated either longitudinally or orthogonally, then it is important to account for the choke skin effect (Sch)c, and a possible additional choke effect (Sfs)c due to the reorientation of the fracture at some distance from the wellbore. The impact of (Sch)c, (Sfs)c and permeability may be illustrated using the values of (Sch)c and (Sfs)c previously calculated and by assuming that PD(tDxf) = 1. QD =



1 PD



(3)



Where: QD = rate (dimensionless) PD = pressure (dimensionless). QD =



1 PD + ( Sch )c + ( S fs )c



(4)



Where: QD = rate (dimensionless) PD = pressure (dimensionless) (Sch)c = choke skin effect (dimensionless) (Sfs)c = additional choke effect (dimensionless). Applying , for the 1.0-md case, QD = 0.563 (a 44% reduction in flow capacity). For the 0.1-md case, QD = 0.928 (a 7% reduction in flow capacity). DOWELL CONFIDENTIAL



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For hydraulic fractures that propagate orthogonally, the factors that will determine whether multiple orthogonal fractures will be an economic proposition are the kh product and the in-situ fracture permeability (kf). In cases when the kh product is large or the kf is relatively small or both, then the choke skin effect will be large, resulting in the productivity of each hydraulic fracture being considerably less than that of a comparable hydraulic fracture in a vertical well. In the case of a longitudinal hydraulic fracture which propagates within a few degrees of the axis of the wellbore, the productivity of the fracture will not be reduced by the effects of either (Sch)c or (Sfs)c. The increased productivity is instead a function of fracture conductivity and the ratio of the length of the horizontal fracture to the height of the reservoir. Therefore, longitudinal fractures may be better suited to relatively thick reservoirs. 3.4 Coning Effects When considering the possible gains made by hydraulically fracturing a horizontal well, it is important to not overlook the way that water and gas coning in the reservoir may be affected by the planned stimulation treatment. These effects may be modeled using a black-oil reservoir simulator such as “Eclipse” (Ben-Naceur and Touboul, 1987). 3.4.1 Comparison of Fractured and Nonfractured Reservoir Assuming the vertical permeability to be equal to the lateral permeability, the creation of a fracture may significantly delay the occurrence of water coning. Water breakthrough time is governed by fracture characteristics (length, conductivity and relative penetration). The value of the vertical permeability has a dramatic effect on water production, a ratio of vertical to horizontal permeability of less than one-tenth results in a significant decrease of coning problems. 3.4.2 Effect of the Distance From the Fracture to the Water Zone Fig. 8 shows the evolution of the water-cut for different vertical penetrations of a fracture into the water zone for a viscosity (mobility) ratio between oil and water of 2. For low-mobility ratios, the initial evolution of the watercut versus time is flat, then increasing linearly with time. For high-mobility ratios, water breakthrough will occur in a matter of days. Actual breakthrough may occur even earlier due to viscous fingering.



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Fig. 8. Water breakthrough time versus the position of the fracture with respect to the oil/water contact. Production rate (drawdown) also has a dramatic effect on the severity of water coning as shown in Fig. 9, where the water-cut curves are compared for a constant rate of 100 BOPD and 1000 BOPD.



Fig. 9. Production rate versus water-cut. Fig. 10 shows the effect of fracture conductivity on water-coning rates for a vertical permeability of 0.1 kh. Three values of fracture conductivity are considered (10, 1, and 0.1). After 1000 days, there is a ratio of 2 between the water-cut fractions corresponding to a 10-fold increase in fracture conductivity.



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Fig. 10. Fracture conductivity versus water-cut.



4 Rock Mechanical Properties The initiation and propagation of a hydraulic fracture from a horizontal wellbore is a complex phenomenon. A successful hydraulic fracturing treatment cannot be designed without understanding the mechanisms that control the initiation and propagation of a hydraulic fracture. This involves a detailed study of the mechanical properties of the formation at the borehole and some distance away from it. The orientation of the borehole with respect to the principle stresses and the relative magnitude of the stresses are key factors in determining how a fracture initiates and propagates within the formation. In cases when fracturing is planned as part of the completion, the mechanical properties of the reservoir should be determined prior to drilling the horizontal wellbore section. The borehole can then be oriented, with respect to the principal stresses, to allow fractures to propagate in the direction that will optimize well productivity. Fracture orientation versus productivity is discussed in Section 3. 4.1 Openhole Wellbore Stability The following potential failure mechanisms should to be considered while drilling, or in the case of an openhole completion. • shear failure •



tensile failure



•



matrix collapse.



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In the case of ductile rock, hydrostatic pressure in the wellbore (less than the radial stress acting around the wellbore) will result in nonelastic inward movement of the borehole and in-hole ellipticity. 4.2 Shear Failure Shear failure is associated with a shearing movement along one or more planes of failure and is a function of the medium's unconfined compressive strength and the angle of internal friction. It can result in active inward movement during production or a passive outward movement during pressurization. 4.3 Tensile Failure Tensile failure is of the most interest when considering initiation and propagation of a fracture because the same stresses are present in the formation after running and cementing a liner. When the maximum tensile stress near the borehole equals the tensile strength of the medium, two kinds of tensile failure can be envisioned and the fracture trace can theoretically be at an angle to the borehole axis. The second kind does not intersect the borehole, is concentric, and alone is kinematically stable. 4.4 Matrix Collapse Matrix collapse can occur in a poorly consolidated formation and in rocks which have unusually large porosity. These formations generally have diagnostic Mohr failure envelopes (Fig. 11). This failure is associated with a volume reduction and densification of the medium. It may also be accompanied by a drastic reduction in permeability and, consequently, a large and sudden decrease in production. Matrix collapse may be associated with strain hardening, which prevents further deformation.



Fig. 11. Mohr failure envelope for matrix collapse. DOWELL CONFIDENTIAL



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4.5 Cased-Hole Wellbore Stability The borehole may be completed in one of the following ways. • Noncemented slotted or preperforated liner with or without external casing packers. This is analogous to an openhole situation with the restriction that progressive failure and squeezing may be reduced due to the presence of the liner. •



Cemented casing, perforated or slotted locally or along the entire length. This is a composite configuration consisting of discrete layers; casing, cement sheath and formation.



Presuming that the casing is not parted” by movement along faults or other tectonic features such as movement initiated by drilling, fluid loss or leakoff during fracturing, several modes of failure behind the casing are possible.



Creep This is progressive, inward, mostly nonrecoverable movement of the formation and can ultimately cause the casing to fail. Salt, potash and some sands are particularly susceptible to this time-dependent phenomenon.



Differential Consolidation As with matrix collapse around an openhole, production may lead to compaction of a particular horizon, The associated subsidence of the overburden may then separate the casing by longitudinal tensile-failure.



Perforation Failure Perforation stability is an important consideration. In general, stress prediction around a perforation requires numerical simulation. As a first approximation, a perforation can be regarded as an openhole subjected to a complex loading condition within the stress field generated by the borehole. Fig. 12 shows an example of stress contours prevailing at the junction of a perforation with the borehole. The orientation of the wellbore with respect to the in-situ stress field may be a stabilizing or destabilizing factor.



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Fig. 12. Stress distribution around a perforation. 4.6 Stress and Deformation Analysis Plastic effects, nonlinear effects (that is, stress-dependent elastic constants) and time-dependent effects (that is, viscoelastic or viscoplastic behavior) must be taken into account if wellbore stability rather than fracture initiation is being considered.



5 Fracture Initiation And Propagation The fracture initiation pressure, location on the wellbore where the fracture starts, and initial fracture orientation depend on the stress-state prevailing at the wellbore. Consequently, the equations developed for borehole stability and openhole elastic deformation can be used to predict how a fracture will initiate from the wellbore. 5.1 Initiation Pressure Fracture initiation from the wellbore is a tensile failure process which can be predicted by the position of in-situ stresses around the wellbore. Tensile failure occurs when the minimum principal stress exceeds the tensile strength (σo) of a formation. By pressurization of the wellbore, tensile stresses are induced, diminishing compressive stress concentration around the wellbore. At the point where the maximum tensile stress exceeds σo, a hydraulic fracture will initiate. Since the stress concentration around a wellbore is a function of the wellbore inclination and orientation with respect to the principal horizontal stresses, the initiation pressure is also a function of these two variables. Fig. 13 illustrates this concept. The required initiation pressure is a function of α and the borehole inclination where α is the angle between the borehole and the minimum principal stress). The example shows that, as the orientation of the wellbore changes, so does the pressure required for failure either in tension as the wellbore is DOWELL CONFIDENTIAL



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pressurized, or in shear as the wellbore is produced. Initiation pressure increases as the differences between the principal stresses decrease.



Fig. 13. Initiation pressure as a function of α and the borehole inclination. When the wellbore is drilled parallel to the direction of the minimum horizontal stress (a = 0), a fracture is initiated at the highest pressure. When α = 90, the fracture initiates at the lowest pressure. 5.2 Fracture Initiation In cases when σv < σHmax, fracture initiation will occur at ψ = ο, π where ψ is the angle measured counterclockwise from the top of the wellbore (Fig. 14).



Fig. 14. Horizontal well configuration in the in-situ stress field. DOWELL CONFIDENTIAL



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At the points of initiation y = 0 and π, the initial fracture will extend at an angle γ within the tensile region created by the borehole pressure. The angle can be determined using Eq. 5. 2σ ψz γ = 1 / 2 tan − 1 (5) σψ − σz



Fig. 15. Initiation points and fracture orientation on the borehole. Where σψ , σz, and σψ z are the tangential, axial, and shear stresses at the point of initiation on the wellbore (Fig. 15). σψ , σz, and σψ z are a function of the wellbore orientation with respect to the principal in-situ stresses (θ); γ is also a function of θ (Fig. 16).



Fig. 16. Fracture initiation pressure. DOWELL CONFIDENTIAL



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The initial fracture extends in the tensile zone until at some distance from the wellbore it turns to become normal to σHmin. The maximum length of the initial fracture can be calculated using Eq. 6. L f = D cosec γ



sin



ψt 2



(6)



Where: Lf = length of the initial fracture (ft) D = wellbore diameter (ft) ψt = angle encompassing the tension zone (degrees). The angle σψ t is determined from the circumferential distribution of tensile stresses that are induced around the wellbore due to pressurization. The location of fracture initiation on the wellbore, breakdown pressure and initial direction of fracture growth along the wellbore can be determined by using the results of a Differential Strain Curve Analysis (DSCA) performed on an oriented core sample. 5.3 Fracture Propagation Hydraulic fracture propagation is very important in terms of possible fracture interaction in the following cases. • multiple fractures transverse to the wellbore treated in individual stages •



multiple longitudinal fractures collinear along the wellbore treated in individual stages.



5.4 Longitudinal Fractures When the minimum stress is perpendicular to the wellbore and the fractures will not rotate away from the wellbore, the fractures will not sense the presence of other fractures until their tips are extremely close. Spacing between the zones to be treated can be approximately determined on the basis of the desired length of the individual fractures. Fig. 17 shows the effect of the distance between such fractures on their width.



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Fig. 17. The effect of distance between collinear fractures on maximum fracture width. 5.5 Angled Fractures In cases when the wellbore is at an angle to the principal stresses, the fractures will only initiate collinear to the wellbore and then rotate away from the wellbore. Normally, inducing a fracture in one zone would alter the existing stress field around the fracture for a certain distance from it. A second fracture created in this localized stress field would be subject to these stresses, and hence may not be parallel to the first fracture. Studies have indicated that the second fracture will rotate toward the first fracture due to the change of minimum horizontal stress in the localized stress field. The degree to which a second hydraulic fracture will rotate as a result of the stress field induced by the first hydraulic fracture is a function of the ratio of minimum horizontal stress to the maximum horizontal stress and net pressure. Increasing Young's modulus or propped fracture width results in a higher net pressure and causes greater rotation of the second hydraulic fracture. The normal distance between two fractures created from two intervals spaced a distance from each other in the same wellbore can be determined using Eq. 7. d = S cosθ Where: d = distance between two fractures S = interval spacing θ = well deviation from σHmin.



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Once the normalized spacing (2d/h) is greater than 3, little if any rotation takes place (Fig. 8).



Fig. 18. Fracture rotation angle versus spacing. 5.6 Transverse Fractures Numerical studies indicate that transverse fractures do not influence each other unless their dimension, minimum height, or penetration approaches their spacing (Fig. 19). The interaction entails increased treatment pressures, reduced width and possible rotation of the fractures (Fig. 20). Interaction is proportional to fracture width and spacing. A previously propped fracture will influence a propagating fracture in proportion to its propped width.



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Fig. 19. Width and excess pressure as a function of spacing for parallel, transverse and radial fractures. 5.7 Controlling Fracture Reorientation Experiments have shown that when the minimum principle stress is not at an angle of either 0° or 90° to the wellbore, induced fractures can be nonplanar and Sshaped. Two factors control the radius of the curvature, the pump rate and the ratio between the maximum and minimum horizontal stresses. Analytical and experimental studies have indicated that the radius of reorientation increases with increasing pump rate, and that the radius of reorientation decreases as the ratio between the maximum and minimum horizontal stresses increases (Fig. 20).



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Fig. 20. Radius of fracture reorientation as a function of the ratio between the maximum and minimum horizontal stresses. Qualitatively, an analysis can be made for a wellbore drilled at any angle to the principal stresses, using stress components normal to, and along the wellbore. Practically, the ratio between the maximum and minimum horizontal principal stresses represents a pre-existing state of stress and when it is greater than two, the radius of reorientation cannot be easily changed by increased pump rate alone.



6 Perforating Hydraulic fractures frequently propagate in a direction different than the direction they initiated, due to the relative orientation of the wellbore with respect to the in-situ stresses. A fracture will initiate at a preferred location on the wellbore and extend at angle γ with respect to the borehole (Fig. 15) until at some distance from the wellbore it turns to become normal to σmin. The initial fracture length is a function of both γ and ψτ. Consequently, Lf is a function of the angle of the wellbore with respect to the axis of minimum principal stress. Lf has previously described in Eq. 6. Along the length of Lf, perforations can be connected to each other by the initial fracture. However, when two perforations are separated by a distance greater than Lf, two independent fractures may be initiated. Therefore, Lf may be used as a parameter to estimate the critical distance between two perforations beyond which more than one initial DOWELL CONFIDENTIAL



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fracture can be created. Fig. 21 illustrates Lf plotted against the orientation of the wellbore with respect to the minimum principal stress where D is the diameter of the wellbore.



Fig. 21. Critical distance between perforation versus well orientation. In view of the angle γ at which Lf extends along the wellbore, 120° or 60° phased perforating is recommended at the highest possible shot-density. This will ensure that the fracture will be in contact with the greatest number of perforations, minimizing perforation friction pressure and additional choking of the fracture due to limited contact with the wellbore. As a general guideline, the distance between the perforations should not exceed the wellbore diameter and the length of the perforated interval should theoretically not exceed four times the wellbore diameter, if only one fracture is to be initiated within the length of the perforated section. The friction pressure across the perforations may require a longer perforated interval or the use of larger perforating guns. Some operators use phased guns (0.7-in. perforations, 4 spf) to perforate two to five ft along the wellbore, commonly three ft. Penetration is an important consideration in a horizontal wellbore because the casing will frequently be uncentralized, resulting in a thicker than anticipated cement sheath on the high side of the wellbore. However, penetration must not be obtained at the expense of perforation size. A minimum 0.6-in. perforation diameter is required if the proppant concentration will exceed 6 PPA. The final selection of charges and guns should be made in conjunction with wireline and testing services. For an orthogonal fracture, theoretically γ = 90° and the casing should be slotted rather than perforated to maximize the area of the wellbore in contact with the fracture. The ABRASIJET* technique is ideal for slotting the casing. *



Mark of Schlumberger



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In the case of a longitudinal fracture, theoretically γ = 0° and, therefore, the length of the perforated interval should not be critical. However, it is unlikely that a well will be drilled exactly in the direction of σHmax. In an extensively perforated or poorly cemented cased-hole completion, unexpected longitudinal fracture initiation may occur when the well is drilled in the direction of the minimum stress, due to the influence of the near-wellbore stress field. In this situation, the fracture will rotate to become perpendicular to the minimum stress direction as it propagates away from the wellbore.



7 Treatment Design The principal difference between designing a successful fracturing treatment in a horizontal well as opposed to a vertical well is understanding the way that the fracture will propagate from a horizontal wellbore. When fracturing of more than one interval is planned, care must be taken to avoid possible interference and communication between the fractures. This requires that a detailed study of the mechanical properties of the wellbore be conducted prior to designing the fracturing treatment. Despite the very obvious differences noted above, the basic steps that have to be followed when designing a fracturing treatment in a horizontal well are similar to those for a vertical well. Outlined below are the steps of the procedure required to design a successful fracturing treatment, taking into account the orientation of the wellbore with respect to the axis of the minimum principal stress. 7.1 Net Present Value Analysis An analysis can be used in conjunction with the procedure outlined below to determine the productivity and NPV of orthogonal fractures in a horizontal well. However, for a complete analysis, or in the case of longitudinal fractures, it will be necessary to use a block-matrix reservoir simulator. 7.1.1 Calculating the NPV of Orthogonal Fractures The following procedure can be used to estimate the NPV from one or more orthogonal fractures to optimize the number of fractures. The procedure provides an approximation to transient flow for comparative purposes and is not proposed as a substitute for a reservoir simulator.



Procedure 1.



Select the number of fractures (n) and the distance (L) between them.



2.



Determine the drainage radius (re) and the drainage area of each fracture using an approximate fracture length.



3.



Using NPV analysis, optimize the production from the fracture in terms of fracture geometry.



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4.



Using cumulative production versus time, divide the cumulative production by the number of days the well has produce to determine average production (q) during this time period. If the NPV program uses a transient solution (rather than a simplified steady-state solution), this average includes flush production.



5.



Calculate the average dimensionless pressure (pD) without a skin using Eq. 8: pD =



∆P 2π kh / µBO q



(8)



Where: pD = average pressure (dimensionless) ∆P = P - Pwf (psi) k = permeability (md) h = reservoir thickness (ft)



µ = viscosity (cp) Bo = STB/res bbl q = time period. 6.



Determine the production with a choke skin effect using Eq. 9. qs = α



1 pD + S



(9)



Where: qS = production with choke skin effect α = ∆P2πkh/µBO pD = average pressure (dimensionless) S = choke skin factor derived from Eq. 1. 7.



Determine the ratio of production with and without a choke skin effect (β) using Eq. 10. β=



qs q



(10)



Where: β = ratio of production with and without choke skin effect qS = production with choke skin effect q = production without choke skin effect. Eq. 9 and Eq. 10 can also be used to account for a choke effect due to the reorientation of the fracture (Sch)c. (Sch)c and (Sfs)c may be combined and substituted for S. DOWELL CONFIDENTIAL



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Determine the total NPV of the fractured horizontal well at a given point in time using Eq. 11. NPV fr = n {$ / bbl × discount (Cβ ) − FC }



(11)



Where: NPVfr = total NPV of the fractured well



9.



C



= cumulative production without skin (determined using the FracNPV software)



β



= f(qs/q)



FC



= fixed cost ($) of one fracture



n



= number of fractures.



Optimize the number of fractures by repeating this procedure with various values of n and comparing NPVfr. The incremental NPV of a fractured horizontal well over an unfractured well can only be determined of the cumulative production from the unfractured well can be determined for the same time period. The incremental NPV is determined using. NPV



Incremental



= NPV fr − NPVh



(12)



Where: NPVfr = total NPV of the fractured well NPVh = NPV of the unfractured well. 7.1.2 Horizontal Well Production Prediction The pressure response of a horizontal well will act like the pressure response of a hydraulically fractured vertical well when the dimensionless length of the horizontal well is greater than four (Eq. 13). LD =



L 2h



kv kh



(13)



Where: LD = fracture length (dimensionless) h = fracture height (ft) kv = vertical permeability (md) kh = horizontal permeability (md). The boundary conditions for a fully penetrating infinite-conductivity fracture are • uniform flux: the same production rate per unit of fracture length DOWELL CONFIDENTIAL



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Horizontal Wells



Dowell



infinite conductivity: no pressure drop along the length of the fracture.



A uniform flux condition is not reasonable to presume in the case of a horizontal well. Therefore, infinite conductivity is the only valid boundary condition. The following correlation may be used to calculate the deviation of an infinite-conductivity horizontal wellbore from that of a fully penetrating, infinite-conductivity fracture of the same length in a vertical well (Eq. 14). log S' = A' − B' log LD + C' (log LD ) 2



(14)



This is valid for 0.1 ≤ LD ≤ 100 and 0.125 ≤ zwD ≤ 0.5, and for 0.1 ≤ LD ≤ 25 and 0.0625 ≤ zwD ≤ 0.125. The constants A’, B’ and C’ are given as — A′ = A1 + A2 log rwD + A3 (log rwD)2 B′ = B1 + B2 log rwD + B3 (log rwD)2 C′ = C1 + C2 log rwD + C3 (log rwD)2 for 10-4 ≤ rwD ≤ 10-2. The values of A1 through C3 are provided in Table 2.



Table 2. Pseudoskin Factor Correlation Contstants Well Location zwD



0.5



0.25



0.125



0.0625



A1



-0.8761



-0.5475



0.02620



0.1027



A2



-0.6829



-0.4778



-0.1599



-0.1369



A3



-0.08058



-0.04881



-0.003549



-0.0007541



B1



2.8521



2.4183



2.1247



1.8377



B2



0.9297



0.6929



0.5502



0.4048



B3



0.1243



0.09135



0.07284



0.05342



C1



-1.1258



-1.1817



-1.7673



-1.4129



C2



-0.4764



-0.5726



-0.9499



-0.7704



C3



-0.05145



-0.07205



-0.1296



-0.1067



Constants



The correlation shown in Eq. 14 demonstrates that the pseudoskin factor (S′) is strongly dependent on LD and rwD. S′ (a positive number) should be added to the horizontal skin factor, Sh (Eq. 15 and Eq. 16). Sh = 1n ( rw′ / rw ) DOWELL CONFIDENTIAL



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Horizontal Wells Sh = S ′ − 1n ( rw′ / rw )



Section 1000 May 1998 Page 33 of 43 (16)



When S′ is less than 0.5, it indicates that the horizontal well can be treated as a fully penetrating infinite conductivity vertical fracture. In this case, single-phase production forecasting may be done as follows. 1.



Assuming a square drainage area with dimensions of each side being 2xe, calculate 2xe /L.



2.



Calculate TD for the time of interest (Eq. 17).



TD = 3.



0.001055kt φµct L2



(17)



Determine qD using the values calculated in step 1, step 2 and Fig. 22.



Fig. 22. Single phase flow The simple solution outlined above is valid for 1 < 2xe /L < 5 and for values of TD shown in Fig. 22. Beyond this range, an exponential type curve (Fetkovich, 1980) can be used substituting wellbore radius (rw) for and effective wellbore radius of L/4 for L/xe < 0.4. In cases when S′ (calculated from Eq. 14) is greater than 0.5, it indicates a deviation of the horizontal well solution from that of a vertically fractured well. Then a pseudosteady-state solution can be used to forecast production from the horizontal well.



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7.2 Fracture Height The vertical propagation of the fracture versus net pressure must be determined. This should be done using data from oriented cores taken from the reservoir, as well as the boundary formations, and can be supplemented by running a FracHite* log in an offset well. The FracHite log is another way the Mechanical Stability Log data can be presented. Although the pressure required to initiate the fracture at the wellbore is dependent on its orientation with respect to the principal in-situ stresses, the net pressure required to propagate the fracture away from the effect of near wellbore stresses will be the same as that for a vertical fracture propagating from a vertical well within the same formation. However, the treating pressure will be determined by the net pressure required to exceed the closure pressure of the fracture in the near-wellbore stress field. For this reason, boundaries which are effective when fracturing offset vertical wells may not be effective in containing a hydraulic fracture initiated from a horizontal wellbore (Fig. 13). 7.3 Fracture Orientation The exact orientation of the wellbore with respect to the three principal axes of stress must be known, as well as the numerical values of these stresses. This will require that the DSCA technique is used on an oriented core sample, and that the orientation of the wellbore is known. The orientation of the wellbore with respect to the axis of principal stress will determine the orientation of the fractures, with respect to the wellbore and breakdown pressure. 7.4 Fracture Length and Conductivity When the fractures are orthogonal to the wellbore, fracture length and conductivity are initially determined in exactly the same way as for a vertical well by using the FracCADE software. However, the effect of the additional choke skin effect due to limited contact with the wellbore and a possible pseudoskin factor due to the changing orientation of the fracture as it propagates, must be taken into account when considering the NPV. 7.5 Pump Rate If the wellbore is not aligned with a principal stress axis, then a high pump rate is required to increase the radius of the fracture as it reorients to align with the in-situ principal stresses. However, perforation friction pressure must be taken into account. 7.6 Fracturing Fluid Selection The fluids used in a vertical well may be used in a horizontal well.



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Dowell



Horizontal Wells



Section 1000 May 1998 Page 35 of 43



Limitations • The fracturing fluid must have proppant suspension properties adequate to prevent settling in the horizontal wellbore section during injection. •



Crosslinker and breaker schedules should be designed to ensure the fracture retains near-wellbore conductivity and to ensure that proppant is not dragged out of the fracture when producing the well. The fracturing fluid viscosity must be reduced as much as possible prior to flowback.



7.7 Proppant Selection The proppant type, size and concentration are important parameters for success of the fracturing treatment. 7.7.1 Mesh Range The treatment should be tailed-in with larger (or higher-strength) proppant to maximize near-wellbore conductivity and to offset any effects of irregular fracture geometry. 7.7.2 Proppant Type The closure pressure at the wellbore will vary as a function of the wellbore orientation. When optimizing the proppant selection, this should be accounted for. Tail-in with a higher-strength proppant should be sufficient. Closure pressure can be accurately determined using the DataFRAC∗ Service or may be approximated from DSCA. 7.7.3 Proppant Concentration The proppant concentration should be ramped-up as high as possible during the final stages to maximize near-wellbore conductivity and to minimize the pseudoskin effect. This is more critical when creating multiple transverse fractures. Tail-in with resin-coated proppants is recommended to prevent proppant flow back during flowback operations or dropout during production.



8 Execution 8.1 Perforating Perforating considerations are • the length of each interval to be perforated



∗



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•



whether to perforate all the intervals individually at the time of the fracturing treatment or all at one time prior to initiating the fracturing treatments



•



perforation density, charge type and perforation size



•



orientation of the perforations in the wellbore.



8.1.1 When to Perforate When to perforate is usually an economic consideration. The possibility of saving rig-time by perforating all the intervals at one time must not be allowed to outweigh the operational advantages of perforating each interval at the time of the fracturing treatment. These operational advantages are • The packer seat can be pressure tested prior to fracturing each interval. •



Tools activated by annulus pressure can be used in the tool string. This is an important consideration when the problems associated with mechanical manipulation of a tool string in a horizontal wellbore.



•



Annulus pressure can be applied while fracturing, preventing excessive differential pressure across the packer.



•



When running the tool string into the well, packer elements are not liable to be damaged by being dragged over perforations.



•



The unfractured reservoir will not be exposed to the kill fluid in the annulus for an extended period of time, with the associated potential problems of lost circulation and formation damage.



8.2 Wellbore Isolation Between Fractures A cemented liner is usually necessary to ensure positive zonal isolation. Operational considerations are: • the length of interval to perforate •



isolation while fracturing each interval



•



fracture spacing to avoid possible interference.



The most common techniques used for wellbore isolation are: •



isolation using mechanical tools



•



isolation using proppant plugs



•



isolation using viscous plugs.



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Horizontal Wells



Section 1000 May 1998 Page 37 of 43



8.2.1 Isolation Using Mechanical Tools In medium- and large radius horizontal wells, the individual fractures can be isolated with bridge plugs and packers. This method of isolation is expensive and risky. Any foreign material that falls to the bottom of the wellbore can become a potential problem. Cleanout procedures must be undertaken with great care before tools are run into the horizontal section. If the tools become stuck, the process to remove them and clear the wellbore can be costly and time consuming. Nitrogen services can be used to improve these cleanout procedures. Stabilized foams may be much more efficient in removing debris than conventional completion fluids. The following criteria should be considered when deciding to use, or selecting a tool string. • The tool string is only run into the well once. It does not require tripping out of the wellbore between treatments. •



Fractures are protected from the kill fluid in the annulus even when moving the tool from one interval to another, or in the event that the tool string must be “redressed”.



•



Circulation or reverse-circulation can be accomplished before and after the fracturing treatment(s).



•



The tool sting is operated with limited pipe movement involving (preferably) no rotation of the drill string.



•



There should be a positive surface indication that the tool string is functioning properly.



•



The diameter of the wellbore after the fracturing treatment should not be restricted by parts of the tool string left permanently in the wellbore.



8.2.2 Isolation Using Proppant Plugs Intentional screenout and multidensity/multimesh proppant are techniques used for wellbore isolation. These two techniques have much less inherent risk and are less expensive than mechanical tools. A simple cleanout trip to dress-off the end of the proppant plug should be the only additional workover time. Complete cleanout will not be as imperative as with bridge plugs and packers because the only tools to be run along the horizontal section are the perforating tools. Perforating tools have a larger tolerance between the tool and the casing than the bridge plugs and packers. 8.2.2.1 Intentional Screenout Another method of isolating the fracture is to attempt to intentionally screen out at the end of the treatment by pumping ultrahigh proppant concentrations. By design, this should leave a plug that will ensure isolation. The proppant plug will be most effective if a curable resin-coated proppant is used. The resin coating can keep the



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proppant in place and can help prevent proppant settling or movement when the next set of perforations is pumped into. The disadvantage of this isolation method is that it is extremely difficult to determine the proppant concentration that will result in a wellbore screenout. If the well does not screenout, or if the proppant is not set with a resin to prevent movement, a channel will form at the top of the wellbore above the proppant and isolation will not be achieved. 8.2.2.2 Multidensity/Multimesh Proppant A method of isolation similar to intentional screenout is to follow the last proppant stage with a multidensity/multimesh proppant stage displaced with a matched density, high-viscosity fluid. This technique involves cutting the flush volume slightly short, and allowing fracture closure to occur. The multidensity/multimesh proppant is then pumped or squeezed into place against the proppant in the fracture. The multiple densities ensure that some of the material falls to the bottom of the wellbore, some rises or floats to the top, and other material fills the center portion. The multidensity/multimesh proppant mixture can be obtained by combining sand with products used in the INVERTAFRAC* Service. The multiple mesh-sizes provide a good means of obtaining a pressure differential to ensure fracture isolation. The various mesh-sizes must be selected carefully to ensure that the smallest material is larger than the proppant-pack pore-throat openings. This will prevent any further damage to the proppant-pack permeability. The weighted displacement fluid will help assure that the material stays together as a plug during pumping operations and can aid during the compaction process that follows by acting in a method similar to a wiper plug. 8.2.3 Isolation Using Viscous Plugs The PROTECTOZONE* service may be used as a method for wellbore isolation. Using the PROTECTOZONE fluid for isolation will eliminate many of the risks associated with mechanical tools or proppant plugs. The plug can be easily placed and does not have the potential inconsistencies of settling or incomplete placement as does a proppant plug. A breaker is added to the mixture and degrades the plug to a pumpable viscosity in a predetermined time. This method of isolation does not require expensive cleanout trips because solids that can interfere with the running of perforating tools are not introduced into the wellbore.



*



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Dowell



Horizontal Wells



Section 1000 May 1998 Page 39 of 43



8.2.4 Wellbore Isolation in an Openhole Completion The simplest isolation technique in an openhole completion is to use diverting agents such as FIXAFRAC∗ J66 Diverting Agent or FIXAFRAC J227 Diverting Agent. This technique has several disadvantages, the greatest of which is the lack of control over the spacing of fracture initiation points along the borehole. All of the fractures are likely to initiate over one small interval along the borehole rather than space themselves over the entire length. Another disadvantage is the lack of control of proppant placement near the wellbore during a diversion stage. Over-displacement of the proppant is likely, leaving an area of low conductivity in the fracture near the wellbore. 8.3 Flowback The well should be cleaned-up as quickly and efficiently as possible while minimizing the amount of proppant produced back from the fracture. This is especially critical when the fracture has limited contact with the wellbore, and near-wellbore conductivity is critical to the success of the treatment. Recommendations are • Prior to flowback, assure that the fracture has closed. •



Flow the well at a reduced rate.



•



Ensure that the residual viscosity of the fracturing fluid is minimized by using an aggressive breaker schedule.



It is unlikely that any proppant that comes out of the fracture during flowback will be transported to the surface. The natural tendency will be for the proppant to settle on the low side of the hole. Therefore, the fact that proppant is not observed on the surface while flowing the well does not mean that the fracture is not producing proppant.



∗



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9 Overview of the Horizontal Well Treatment-Design Procedure An overview of important fracture treatment design considerations for horizontal wells is provided in Table 3.



Table 3. Overview of Fracture Treatment Design Considerations for Horizontal Wells Item Fracture Orientation



Consideration DSCA, wellbore inclination and azimuth.



Fracture Height



Contained, unconfined — function of net pressure required to initiate the fracture.



Fracture Model



Radial — no boundaries. PKN — with boundaries.



Fracture Length and Conductivity



Choke skin effect and pseudo-skin due to reorientation.



Fluid Selection



Proppant transport, optimized crosslinker and breaker schedule.



Proppant



Type, size, concentration and strength.



Maximum Proppant Concentration



Increased concentration at the wellbore.



Prepad



Optimized using the FracNPV software.



Treatment Volume



Optimized using the FracNPV software.



Pad Volume



Optimized using the FracNPV software.



Stage Volume/Concentration



Optimized using the FracNPV software.



Pump Rate



Increased rate to increase radius of reorientation.



Perforations



Length of perforated interval, phasing density, friction-pressure.



Tubing Size



Friction, tubing movement.



Downhole Tools



Movement with sand in the wellbore, weight at the toolstring.



Surface Equipment



Same as a vertical well.



Flowing the Well Back



Proppant production — increased choke skineffect.



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Horizontal Wells



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Section 1000 May 1998 Page 41 of 43



10 Case History The well was drilled vertically through the reservoir to determine the magnitude and orientation of the principal stresses. Oriented cores were obtained from the barriers and the formation.



Well Data TVD = 10,048 ft Casing Size = 9.625, 5/8-in. Casing Shoe = 7245 ft Kickoff = 7400 ft Deviation = 90° at 8000 ft Openhole = 8.5-in. Liner Size = 5.5-in, 17 lbm/ft Liner Top = 6416 ft Centralizers = 1 every 20 ft BHST = 150°F (66°C) Stress measurements were made using a number of different techniques (Table 4), and the horizontal wellbore section was drilled in the direction of the minimum horizontal stress.



Table 4. Stress Measurement Techniques Test DSCA



Stress Direction N52-84E



Stress Magnitude σHmin = 8.37 - 11.31 kPa/m σHmax = 9.5 kPa/m - 12.89 kPa/m



Micro Frac



σHmin ≈ σHmax 9.95 kPa/m



100 Mesh Sand Injection



σHmin = 24600 kPa ≈ 9.95 kPa/m σHmax = 25650 kPa ≈ 10.40 kPa/m



Acoustic Anisotropy



N 57-80E (Natural Fractures N85E)



FMS (Natural Fractures)



N80-85E



FMS (After Injection)



N55-75E σHmin = 11.31 - 13.57 kPa/m



FracHite U.S.G.S.



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The number of required orthogonal fractures and the fracture geometry were optimized using the FracNPV module in the FracCADE software. Five fractures would be required to maximize the well performance (Fig. 23).



Fig. 23. NPV analysis of the number of orthogonal fractures. All the hydraulic fractures were designed as follows: Gross height = 245 ft Net height = 25 ft Fracture half-length = 543 ft Fracture conductivity = 373 md-ft Average proppant concentration = 1 lbm/ft Each interval was fractured separately via 5.5-in. tubing using 128,200 gal of YF140 and 280,000 lbm of 20/40-mesh sand at 40 bbl/min. The average proppant concentration was 7 PPA. Each treatment was tailed-in with 51,000 lbm of 20/40 mesh resin-coated sand. During the last stage, the proppant concentration was increased to 17 PPA (4000 lbm total) to maximize near-wellbore conductivity.



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Horizontal Wells



Section 1000 May 1998 Page 43 of 43



After the treatment, the well production tested 69 BOPD, 326 BWPD, and 64 Mscfd. This closely matched the predicted fluid production (Fig. 24).



Fig. 24. Actual versus predicted fluid production.



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FRACTURING ENGINEERING MANUAL Appendix A - Fracturing Design-Execution-Evaluation Example



Section 1100 May 1998 Page 1 of 49



APPENDIX A - FRACTURING DESIGN-EXECUTIONEVALUATION EXAMPLE 1 Well Data................................................................................................................................... 3 2 Reservoir Evaluation ............................................................................................................... 3 3 DataFRAC Service.................................................................................................................. 11 4 Treatment Design................................................................................................................... 22 4.1 Fracturing Fluid Selection .................................................................................................. 22 4.2 Proppant Selection............................................................................................................. 22 4.3 Fracture Length Optimization............................................................................................. 24 4.4 In-Situ Stress Data ............................................................................................................. 27 4.5 Approximate Pumping Schedule........................................................................................ 28 4.6 Placement Design .............................................................................................................. 32 4.7 Production Forecast........................................................................................................... 35 5 Treatment Execution ............................................................................................................. 40 6 Treatment Evaluation ............................................................................................................ 42 7 Post-Fracture Well-Test Analysis......................................................................................... 44 FIGURES Fig. 1. Review output for all transients. ........................................................................................ 5 Fig. 2. Diagnostic plot - Transient 1. ............................................................................................ 7 Fig. 3. Wellbore storage - Transient 1.......................................................................................... 8 Fig. 4. Horner plot - Transient 1. .................................................................................................. 9 Fig. 5. Multi-rate type curve and derivative match. .................................................................... 10 Fig. 6. Verification plot. .............................................................................................................. 10 Fig. 7. Production decline. ......................................................................................................... 11 Fig. 8. NODAL analysis.............................................................................................................. 12 Fig. 9. DataFRAC job record...................................................................................................... 13 Fig. 10. Step-rate test. ............................................................................................................... 13 Fig. 11. DataFRAC job record (replotted). ................................................................................. 14 DOWELL CONFIDENTIAL



Section 1100 May 1998 Page 2 of 49 Fig. 12. Fig. 13. Fig. 14. Fig. 15. Fig. 16. Fig. 17. Fig. 18. Fig. 19. Fig. 20. Fig. 21. Fig. 22. Fig. 23. Fig. 24. Fig. 25. Fig. 26. Fig. 27. Fig. 28. Fig. 29.



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Pressure analysis ..........................................................................................................14 Closure pressure estimation.......................................................................................... 16 “G” plot. .........................................................................................................................18 Net Present Value. ........................................................................................................24 Cumulative production...................................................................................................25 Fracture height-growth history....................................................................................... 35 Wellbore fracture width profile. ......................................................................................35 Fracture height profile. ..................................................................................................36 Production decline. ........................................................................................................40 Cumulative production...................................................................................................40 Post-fracture IPR curves (NODAL analysis)..................................................................41 Job record. ....................................................................................................................42 Pressure analysis (Nolte-Smith plot). ............................................................................43 Job record. ....................................................................................................................44 Pressure analysis. .........................................................................................................44 Linear flow regime. ........................................................................................................47 Vertical fracture, linear flow - Transient 1. .....................................................................48 Multi-rate type curve and derivative match....................................................................48 TABLES



Table 1. Buildup Test....................................................................................................................5 Table 2. DataFRAC Pressure Record ........................................................................................14 Table 3. Pressure Decline Analysis ............................................................................................18 Table 4. Input Data for FracNPV ................................................................................................25 Table 5. Output From the Inverse Module..................................................................................28 Table 6. Output of the PLACEMENT Simulator..........................................................................33 Table 7. Input Data for MLPP Production-Control Input .............................................................36 Table 8. Input Data for MLPP Production-Control Input .............................................................36 Table 9. Input Data for MLPP Production-Control Input .............................................................37 Table 10. MLPP Output ..............................................................................................................38 Table 11. Fracture Geometry .....................................................................................................44 Table 12. Build-up Pressure Response......................................................................................45



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Section 1100 May 1998 Page 3 of 49



1 Well Data The following is an example of a typical DESIGN-EXECUTE-EVALUATE* technique for a gas well that will be fracture simulated. The application of the RampGEL* Service and the CleanFRAC* Service has not been included in this example.



Well Data: BHST



=



210°F (99°C)



Perforations



=



10,750 to 10,900 ft TMD 10,161 to 10,316 ft TVD



Tubing



=



4-1/2-in.; 15.5 lbm/ft



Casing



=



9-5/8-in., 47 lbm/ft to 10,042 ft MD 7 in., 29 lbm/ft to 10,902 ft MD



Net height



=



130 ft



Hole diameter



=



8-1/2-in.



2 Reservoir Evaluation Pressure transient analysis is the best method for estimating permeability and skin. This part of the analysis may be provided by the client. Dowell can provide this analysis if requested. For complex reservoirs, a regional reservoir engineer or stimulation specialist should be consulted. A well test was performed prior to the fracture treatment of this example well. The well was flowed for 100 hr at 800 Mscf/D and then shut in for another 100 hr. The pressure buildup response data are provided in Table 1. The test sequence is shown in Fig. 1. The known reservoir parameters are: Total compressibility



=



0.000103 1 psi



Gas gravity



=



0.65



Viscosity



=



0.0247 cp



Porosity



=



10%



Net Pay



=



130 ft



The data were analyzed using the ZODIAC* (Zoned Dynamic Interpretation, Analysis and Computation) software from Schlumberger. A commercial well test analysis program can also be used.



*



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Section 1100 May 1998 Page 4 of 49



FRACTURING ENGINEERING MANUAL Appendix A - Fracturing Design-Execution-Evaluation Example



Fig. 1. Review output for all transients.



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Section 1100 May 1998 Page 5 of 49



Table 1. Buildup Test Time (hr) 0.1008 0.1128 0.1224 0.1344 0.144 0.1536 0.1632 0.1728 0.18 0.192 0.204 0.2112 0.2208 0.2304 0.24 0.264 0.288 0.312 0.408 0.48 0.552 0.576 0.624 0.696 0.72 0.792 0.816 0.912 0.96 0.984 1.008 1.032 1.056 1.104 1.224 1.344 1.44



Pressure (psi) 1651.9 1667.2 1679.4 1694.6 1706.7 1718.8 1730.8 1742.8 1751.7 1766.6 1781.4 1790.2 1802 1813.7 1825.4 1854.4 1880.9 1907.1 2009.7 2082.7 2150.6 2172.8 2216.7 2280.4 2300.3 2359.2 2378.5 2454.1 2490.1 2507.5 2524.7 2541.8 2558.7 2592.2 2673.6 2748.9 2806.8



Time (hr) 1.608 1.704 1.8 1.92 2.016 2.16 2.232 2.304 2.16 2.4 2.64 2.88 3.12 3.36 3.6 3.84 4.08 4.32 4.56 4.8 5.04 5.76 6 6.96 7.44 8.16 8.64 9.36 9.84 10.8 12 13.2 14.4 15.12 16.08 17.04 18



Pressure (psi) 2903.4 2954.8 3004.7 3064.9 3110.9 3176.3 3207.8 3238.7 3176.3 3278.9 3372.3 3458.8 3538.5 3611.8 3680.2 3743.4 3801.8 3856.4 3907.4 3954.6 3998.6 4114.6 4148.3 4263.5 4311.5 4373.3 4408.9 4455.6 4482.8 4529.6 4576.4 4613.8 4644.3 4659.9 4678.4 4694.5 4708.8



DOWELL CONFIDENTIAL



Time (hr) 20.16 21.36 22.08 23.04 24 26.4 28.8 31.2 33.6 36 38.4 40.8 43.2 45.6 48 50.4 52.8 55.2 57.6 60 62.4 64.8 67.2 69.6 72 74.4 76.8 79.2 81.6 84 86.4 88.8 91.2 93.6 96 98.4 100.001



Pressure (psi) 4735.6 4748 4754.8 4763.2 4770.9 4788 4802.5 4815.1 4826.2 4836 4844.9 4853 4860.3 4867.1 4873.3 4879.1 4884.5 4889.5 4894.2 4898.6 4902.7 4906.6 4910.3 4913.8 4917.1 4920.2 4923.2 4926 4928.8 4931.3 4933.8 4936.2 4938.5 4940.6 4942.7 4944.7 4946



Section 1100 May 1998 Page 6 of 49



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The data were first plotted on a log-log scale for diagnostics (Fig. 2). Real gas pseudo pressures are graphed against shut-in time.



Fig. 2. Diagnostic plot - Transient 1. The data exhibit a unit slope lasting approximately one hour which indicates wellbore storage. The specialized plot for wellbore storage is a cartesian plot of ∆m(p) versus ∆t, shown in Fig. 3. The wellbore storage coefficient is calculated by the software to give c = 0.0371 bbl/psi.



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Fig. 3. Wellbore storage - Transient 1. Infinite-acting radial flow will start at about 1.5 log cycles after the end of wellbore storage. A more definitive indication is to observe the derivative curve. The derivative curve during radial flow will approach a constant value and the dimensionless coordinates equal to 0.5 as shown in Fig. 2. The infinite-acting radial flow regime in this example appeared at about 80 hr after shut-in. If the test is terminated earlier than this time, type-curve matching is the only method required for analysis. The infinite-acting radial flow is analyzed using the Horner method and is shown in Fig. 4. From this analysis permeability (k) = 0.045 md



*



skin (s)



= 3.74



P*



= 5060 psi.



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Fig. 4. Horner plot - Transient 1. Note that the Horner straightline is fitted for the portion of the data shown in radial flow from Fig. 2. The data were next analyzed with the type-curve matching method. This method is particularly applicable to early-time behavior. The log-log plot of ∆m(p) versus ∆t can be matched with Bourdet, et al type curves to calculate the reservoir parameters using the ZODIAC software. The solver in the software will generate the type-curve to match the well test data. The results of the type-curve match are shown in Fig. 5. A verification plot is shown in Fig. 6. The reservoir parameters from this match are k =0.054 md s =5.



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Fig. 5. Multi-rate type curve and derivative match.



Fig. 6. Verification plot.



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The two analyses provide essentially the same result, but the results of the typecurve match will be used because they utilize the complete range of data. Additionally, the infinite-acting radial flow requires a longer test period to fully mature. Production decline curves were then generated to evaluate production before and after a fracture treatment. The FracNPV* module or MLPP (Multi-Layer Production Prediction) module from the FracCADE* software can be used for the evaluation. The FracNPV analysis can provide the direct comparison of fracture and nonfracture production decline curves and is shown in Fig. 7 for a fracture half-length (xf) of 500 ft and a fracture conductivity (kfw) of 800 md⋅ft. (See Fig. 14 in the Treatment Design section.)



Fig. 7. Production decline. Fig. 8 shows the NODAL* production analysis system plot of the producing system. The post-fracture IPR curve for 50 days is generated using the MLPP module for comparison with the prefracture IPR.



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Fig. 8. NODAL analysis. Note that there are some differences of the results of the FracNPV analysis compared to MLPP analysis. The FracNPV software uses an analytical solution and the MLPP software uses a semi-analytical reservoir simulator. The MLPP analysis is more accurate than the FracNPV analysis.



3 DataFRAC Service A DataFRAC* Service was performed prior to the main propped-fracture treatment. The first stage of the test was the DataFRAC calibration treatment which involved injecting 30,000 gal of YF*130HTD into the formation at fracturing rate and pressure. Fluid injection was then stopped and the pressure decline was monitored as the fluid was allowed to leak off into the matrix. The injection rate and pressure for this test is provided in Fig. 9.



*



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Fig. 9. DataFRAC job record. The second stage of the test involved pumping 9.5 lbm/gal CaCl2 brine for the steprate test. The result of the test is shown in Fig. 10.



Fig. 10. Step-rate test. NOTE: From step rate test, upper bound of closure pressure = 6600 psi. flowback was not monitored for this test. DOWELL CONFIDENTIAL



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Pressure was monitored using a dead-string annulus. The hydrostatic pressure of the fluid column was 5050 psi. A hydrostatic pressure of 5050 psi was added to the surface pressure reading to obtain the BHP. The difference between the pressure prior to shutdown and the initial shut-in pressure was approximately 310 psi. A nearwellbore pressure drop of 310 psi was subtracted from the data and replotted (Fig. 11). The data points are shown in Table 2. This data was used for the DataFRAC analysis.



Fig. 11. DataFRAC job record (replotted).



Fig. 12. Pressure analysis. DOWELL CONFIDENTIAL



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Table 2. DataFRAC Pressure Record Time (gal)



Volume (gal)



Rate (bbl/min)



BHP (psi)



Time (gal)



Volume (gal)



Rate (bbl/min)



BHP (psi)



7:36:00



0



0



5184



7:57:00



30185



0



6687



7:37:00



8



1.79



5235



7:57:20



30185



0



6678



7:38:00



269



9.07



6373



7:57:40



30185



0



6671



7:39:00



610



7.95



6315



7:58:00



30185



0



6663



7:40:00



1073



16.82



6482



7:58:20



30185



0



6655



7:41:00



2176



38.82



6668



7:58:40



30185



0



6648



7:42:00



4229



50.75



6786



7:59:00



30185



0



6641



7:43:00



6408



52.55



6858



7:59:20



30185



0



6635



7:44:00



8597



52.67



6914



7:59:40



30185



0



6631



7:45:00



10836



51.3



6957



8:00:00



30185



0



6625



7:46:00



12988



50.95



6935



8:00:20



30185



0



6618



7:47:00



15140



50.95



6923



8:00:40



30185



0



6615



7:48:00



17275



52.44



6908



8:01:00



30185



0



6612



7:49:00



19541



52.54



6896



8:01:20



30185



0



6606



7:50:00



21740



52.98



6884



8:01:40



30185



0



6600



7:51:00



23981



52.94



6864



8:02:00



30185



0



6595



7:52:00



26227



53.07



6859



8:02:20



30185



0



6591



7:53:00



28516



53.24



6845



8:02:40



30185



0



6586



7:53:40



29980



53.24



6838



8:03:00



30185



0



6579



7:54:00



30185



0



6838



8:03:20



30185



0



6573



7:54:20



30185



0



6838



8:03:40



30185



0



6568



7:54:40



30185



0



6803



8:04:00



30185



0



6563



7:55:00



30185



0



6775



8:04:20



30185



0



6554



7:55:20



30185



0



6754



8:04:40



30185



0



6550



7:55:40



30185



0



6735



8:05:00



30185



0



6544



7:56:00



30185



0



6722



8:05:20



30185



0



6540



7:56:20



30185



0



6708



8:05:40



30185



0



6534



7:56:40



30185



0



6698



8:06:00



30185



0



6528



The pressure decline was monitored to evaluate the closure pressure and the fluidloss coefficient.



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Fig. 13 shows the square root time plot of the pressure decline. A distinct slope occurs between 6400 and 6600 psi. Taking the intersection of the two straight lines with different slopes, the closure pressure is estimated to be 6500 psi. This result is consistent with the upper bound of the closure pressure from the step-rate test.



Fig. 13. Closure pressure estimation. Fracture Geometry Fig. 10 shows that during the initial phase of propagation, the pressure increases with injection which indicates PKN-type behavior. The decreasing pressure after the initial phase indicates the fracture grows into the bounding layer. A decreasing pressure profile generally indicates unconfined height growth, keeping in mind that the pressure will increase again if another barrier is encountered. The pressure behavior during injection match the P3D model of the PLACEMENT II module in the FracCADE software (shown in Fig. 12). The P3D model is not supported by DataFRAC module in the FracCADE software at the present time. The analysis assumes PKN-type behavior because the net pressure matches the fracture simulator. Using a radial model provides a very-low net pressure value. Using the closure pressure of 6500 psi, a pressure decline analysis using the “G” function plot was performed. The analysis accounts for height growth and tip recession during shut-in by applying a correction to the standard “G” plot. The P* is taken from the slope at 3/4 ∆P or mG′ (use “recession” option in the DataFRAC module). *



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The result of this analysis, with the net pressure match, is shown in Table 3, and the “G” function plot with the corrected slope is shown in Fig. 14. The net pressure match is obtained by adjusting the Young's modulus (E) and the leakoff height. The results of DataFRAC analysis are gross fracture height



=160 ft



leakoff height



=160 ft



fluid-loss coefficient



=0.0044 ft/min1/2



Young's modulus (E)



= 3.3 x 106 psi.



DataFRAC Screen



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Fig. 14. “G” plot.



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Table 3. Pressure Decline Analysis



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Table 3. Pressure Decline Analysis (continued)



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DataFRAC Pressure Decline Data



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DataFRAC Pressure Decline Data (continued)



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4 Treatment Design 4.1 Fracturing Fluid Selection The BHST is 210°F (99°C). Several fluids are appropriateYF100HTD, YF500HT, and YF600 fluids. A YF100HTD fluid is selected for this example since the crosslink is reversible and therefore is much less sensitive to shear history. YF130HTD is selected for the initial treatment design. The rheological properties (after two hours at 210°F [99°C]) are power-law exponent (n′ )



=



0.77



consistency coefficient (K′) =



0.05



Rheology guidelines for YF130HTD fluid are provided in the Fracturing Materials ManualFluids. Job-specific data was obtained from laboratory testing. The estimated job time is three hours. After three hours, the fluid viscosity at 170 sec-1 ≈ 440 cp, which is still adequate for proppant transport. Breaker J481 is used to degrade the fluid. The approximate breaker concentration is 5 lbm/1000 gal. 4.2 Proppant Selection Fracture conductivity is calculated using Eq. 1. C fD =



kf w × retained permeability (decimal ) keff x f



(1)



Where: CfD = fracture conductivity (dimensionless) kf = in-situ fracture permeability (md) w = fracture width (ft) keff = formation effective permeability (md) xf = fracture half-length (ft). The required proppant permeability is calculated using Eq. 2. kf =



C fD × k eff × x f w × retained permeability



Where: CfD = fracture conductivity (dimensionless) kf = in-situ fracture permeability (md) DOWELL CONFIDENTIAL



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w = fracture width (ft) keff = formation effective permeability (md) xf = fracture half-length (ft) w = retained permeability (decimal equivalent). The permeability of the reservoir is very low (keff = 0.054 md) and a CfD = 10 is used for the design. A dimensionless fracture conductivity greater than 10 will result in a pronounced reduction in the effectiveness of production increase. The estimated retained-permeability factor is 0.2. The retained-permeability factor is a function of postclosure polymer concentration and breaker concentration. Some of these data are provided in the Fracturing Materials Manual  Fluids. The FracCADE software can calculate the retained permeability for borate- and titanatecrosslinked fluids. The propped fracture width is approximately 0.1 in. The optimum fracture half-length is determined using the FracNPV software. The selected fracture length can also be obtained from the client based on the budget. In this case, the optimum fracture half-length is 500 ft (see Fig. 15).



Fig. 15. Net Present Value. The required proppant permeability (using Eq. 2) is 10 × 0.054 × 500 0.1 / 12 × 0.2 = 162,000 md



kf =



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A proppant permeability of 162,000 md is the minimum required to give CfD = 10. The closure pressure is greater than 6500 psi (from DataFRAC analysis). Using the proppant selection guide in Treatment Design, low-density 20/40-mesh intermediatestrength proppant (ISP) is selected to provide the required proppant-pack permeability. 4.3 Fracture Length Optimization The FracNPV module is used to optimize the fracture half-length. The FracNPV software can also be used to select the optimum fluid, proppant and proppant concentration. The plot of Net Present Valve (NPV) versus fracture length is shown in Fig. 15. The optimum fracture length is 500 to 700 ft. The NPV of a 10-md reservoir is also shown to demonstrate the importance of reservoir permeability in fracture design. For the 10-md case, a fracture half-length of less than 200 ft would be sufficient. The fracture half-length of 500 ft is selected for the design. The determination of fracture half-length may also be discussed with the client. Fig. 16 shows the incremental cumulative production for the fracture treatment generated by the FracNPV software.



Fig. 16. Cumulative production. The input data used for the FracNPV are provided in Table 4.



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Table 4. Input Data for FracNPV



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Table 4. Input Data for FracNPV (continued)



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Table 4. Input Data for FracNPV (continued)



4.4 In-Situ Stress Data The following stress profile was obtained using a long-spaced digital sonic log. In-situ stress testing was performed to calibrate the stress profile from the log. The result of the “smooth” calibrated in-situ stress profile is shown below.



Stress Profile



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4.5 Approximate Pumping Schedule The INVERSE module in the FracCADE software was used to generate the approximate pumping schedule. The input fracture half-length of 500 ft was obtained from the FracNPV analysis. The output from the Inverse module is provided in Table 5.



Table 5. Output From the Inverse Module



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Table 5. Output From the Inverse Module (continued)



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Table 5. Output From the Inverse Module (continued)



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Table 5. Output From the Inverse Module (continued)



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Table 5. Output From the Inverse Module (continued)



4.6 Placement Design A preliminary pumping schedule for the optimum length and conductivity was obtained from the INVERSE module of the FracCADE software and validated by running the schedule in the PLACEMENT module. The schedule was adjusted for a more practical value. The output of the PLACEMENT simulator is provided in Table 6. The predicted pressure and fracture geometry are provided in Fig. 17, Fig. 18, and Fig. 19.



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Table 6. Output of the PLACEMENT Simulator



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Fig. 17. Fracture height-growth history.



Fig. 18. Wellbore fracture width profile.



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Fig. 19. Fracture height profile. 4.7 Production Forecast The MLPP (Multi-Layer Production Prediction) module in the FracCADE software is used for production prediction. The MLPP module was introduced in FracCADE V3.4. It is a semi-analytical multi-layer reservoir simulator capable of modeling the performance of commingled multi-layer reservoirs. The MLPP module uses any one of three production modes •



constant production rate



•



constant bottomhole pressure (BHP)



•



constant wellhead pressure (WHP).



A constant wellhead pressure of 1625 psi is selected as the production mode. The constant WHP is the mode of production that is the most common in field practice. This mode should also be selected for generating the NODAL analysis plot. Table 7, Table 8, and Table 9 show the input data for MLPP production-control input. The production mode and tubing flow correlation specification is shown in Table 7. Table 8 shows the production zone data input for each zone. Fracture geometry from the PLACEMENT simulator can be imported or entered manually (Table 8). Table 9 is the multiple-zone data display to show some important data for all specified production zones. Table 10 shows the MLPP output. The production decline, cumulative production and post-fracture IPR curves are provided in Fig. 20, Fig. 21, and Fig. 22. DOWELL CONFIDENTIAL



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Table 7. Input Data for MLPP Production-Control Input



Table 8. Input Data for MLPP Production-Control Input



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Table 9. Input Data for MLPP Production-Control Input



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Table 10. MLPP Output



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Fig. 20. Production decline.



Fig. 21. Cumulative production.



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Fig. 22. Post-fracture IPR curves (NODAL analysis).



5 Treatment Execution The propped fracture treatment consisted of pumping the fluid in accordance with the pumping schedule in the PLACEMENT design. The average injection rate during the treatment was 50 bbl/min. The BHP and flow rate of the job execution is provided in Fig. 23.



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Fig. 23. Job record. The final proppant concentration of 13 lbm proppant added was maintained until the end of the job. The treatment was successfully displaced and placed all 498,000 lbm of 20/40-mesh ISP into the formation. The Nolte-Smith plot is shown in Fig. 24. A period of approximately-constant net pressure occurred at the beginning indicating significant height growth into a stress barrier. The use of a P3D fracture simulator for the treatment design is appropriate. The pressure then began to increase slightly, indicating another barrier was encountered. After about 120 min, the pressure started a more rapid increase. The (approximately) 150 psi pressure increase is attributed to increased slurry viscosity as proppant concentration increased, rather than tip screenout indication.



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Fig. 24. Pressure analysis (Nolte-Smith plot).



6 Treatment Evaluation The evaluation can be applied at several levels.



Execution Evaluation • Service quality evaluation. •



Evaluation of the pumping of fluids at a scheduled rate and specified performance.



Post-Job Evaluation • Evaluation of fracture geometry with the primary evaluation tool being 1. •



The BHP during the actual treatment.



2. Post-fracture well-test analysis. Evaluation of the production results compared to design expectation.



The following evaluations are the post-job evaluation examples based on the BHP during actual treatment and post-fracture well-test analysis (refer to Treatment Evaluation for service quality evaluation and Reservoir Evaluation for evaluation of production results using a well performance tracking form). The P3D fracture simulator was utilized to evaluate the geometry of the propped fracture treatment. The “calibrated” set of parameters obtained from the DataFRAC DOWELL CONFIDENTIAL



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service were used in the propped fracture simulation. Fig. 25 and Fig. 26 show a very good match using the actual data and the simulator. Table 11 provides the fracture geometry generated by the simulator using the actual pumping schedule. The PLACEMENT simulator does not need to be rerun if there is no significant difference between the actual pumping schedule and the design.



Fig. 25. Job record.



Fig. 26. Pressure analysis. DOWELL CONFIDENTIAL



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Table 11. Fracture Geometry



7 Post-Fracture Well-Test Analysis Post-fracture pressure transient tests are available for this well. The well was flowed for 100 hr at 4000 Mcf/D after the fracture treatment and then shut-in for another 100 hr. The build-up pressure response is provided in Table 12. The data obtained from the pre-treatment test (k = 0.054 md) are used for this analysis.



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Table 12. Build-up Pressure Response Time (hr)



P (psi)



Time (hr)



P (psi)



0.1 0.108 0.12 0.132 0.144 0.156 0.168 0.18 0.192 0.204 0.216 0.228 0.24 0.36 0.48 0.6 0.72 0.84 0.96 1.08 1.2 1.32 1.44 1.56 1.68 1.8 1.92 2.04



4695.5 4696.1 4696.9 4697.7 4698.5 4699.2 4699.9 4700.5 4701.2 4701.8 4702.3 4702.9 4703.4 4708.1 4711.8 4715 4717.8 4720.4 4722.7 4724.9 4726.9 4728.8 4730.6 4732.3 4733.9 4735.5 4737 4738.4



2.16 2.28 2.4 3.6 4.8 6 7.2 8.4 9.6 10.8 12 13.2 14.4 15.6 16.8 18 19.2 20.4 21.6 22.8 24 36 48 60 72 84 96 100



4739.8 4741.2 4742.4 4753.6 4762.7 4770.3 4777.1 4783.1 4788.6 4793.7 4798.3 4802.6 4806.7 4810.5 4814.1 4817.5 4820.8 4824 4827 4829.8 4832.6 4856.1 4873.3 4886.9 4898.3 4907.7 4915.8 4918.1



The data were analyzed using the ZODIAC software. A log-log diagnostic graph of buildup test data is provided in Fig. 27. The data exhibit a half slope which is evident from approximately 0.2 hr to 2 hr. This is a strong indication of the presence of a high-conductivity fracture causing the



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linear flow pattern. The specialized plot for the linear flow is a cartesian plot of ∆m(p) versus ∆t1/2 shown in Fig. 28. The fracture length can be estimated from kxf2 =11,219 md•ft2 xf = 456 ft. The inferred fracture length is within 15% of that predicted by the fracture simulator. The data were next analyzed with the type-curve matching method using the solver in the ZODIAC software. The results of the type curve match gives CfD ≈ 84. However, no unique match was obtained. When the CfD, is greater than 30, there is not enough ∆P in the fracture to show uniqueness.



Fig. 27. Linear flow regime.



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Fig. 28. Vertical fracture, linear flow - Transient 1.



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Fig. 29. Multi-rate type curve and derivative match.



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APPENDIX B - FRACTURING FLUIDS 1 Introductory Summary............................................................................................................. 3 2 Water-Base Fluids.................................................................................................................... 4 2.1 Polymers .............................................................................................................................. 4 2.1.1 Guar Gum................................................................................................................... 4 2.1.2 Hydroxypropylguar ..................................................................................................... 5 2.1.3 Hydroxyethylcellulose ................................................................................................. 6 2.1.4 Xanthan ...................................................................................................................... 7 2.1.5 Carboxymethylhydroxypropylguar .............................................................................. 8 2.2 Crosslinkers ......................................................................................................................... 8 2.2.1 Borate Crosslinker ...................................................................................................... 8 2.2.2 Organometallic Crosslinkers....................................................................................... 9 2.2.3 Crosslink Rate ............................................................................................................ 9 2.2.3.1 YF100 and YF200 Fluids ............................................................................... 10 2.2.3.2 YF300 and YF400 Fluids ............................................................................... 10 2.2.3.3 YF500 and YF600 Fluids ............................................................................... 10 3 Crosslinked Oil-Base Fluids ................................................................................................. 11 3.1 YF"GO"III and YF"GO"IV Fluids......................................................................................... 12 4 Multiphase Fluids .................................................................................................................. 12 4.1 Foams ................................................................................................................................ 12 4.2 Energized Fluids ................................................................................................................ 12 4.2.1 The Gas Phase......................................................................................................... 13 4.3 Emulsions .......................................................................................................................... 14 5 Acidic Fluids........................................................................................................................... 15 6 Fracturing Fluid Characterization ........................................................................................ 16 6.1 Rheology............................................................................................................................ 16 6.1.1 Shear and Temperature ........................................................................................... 16 DOWELL CONFIDENTIAL



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6.1.2 Shear Rate ................................................................................................................16 6.1.3 Shear Stress .............................................................................................................16 6.1.4 Apparent Viscosity ....................................................................................................16 6.1.5 Newtonian Fluids.......................................................................................................17 6.1.6 Non-Newtonian Fluids...............................................................................................17 6.2 Slurry Rheology ..................................................................................................................19 6.3 Proppant Transport ............................................................................................................21 6.4 Fluid-Loss ...........................................................................................................................22 6.5 Conductivity Damage from Fracturing Fluids .....................................................................23 6.5.1 The Effect of Water-Base Fracturing Fluids on Retained Permeability .....................24 7 Fluid Selection........................................................................................................................26 FIGURES Fig. 1. The structure of guar. ........................................................................................................5 Fig. 2. The structure of HPG.........................................................................................................6 Fig. 3. The structure of HEC.........................................................................................................7 Fig. 4. The structure of Xanthan. ..................................................................................................7 Fig. 5. Borate crosslinking mechanism.........................................................................................9 Fig. 6. The structure of aluminum phosphate ester chain. .........................................................11 Fig. 7. Power-law exponent of a 40 lbm/1000 gal crosslinked water-base fluid. ........................17 Fig. 8. Consistency coefficient of a 40 lbm/1000 gal crosslinked water-base fluid. ....................18 Fig. 9. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 40 sec-1..........18 Fig. 10. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 170 sec-1.....19 Fig. 11. The effects of proppant on slurry viscosity of a Newtonian fluid....................................20 Fig. 12. The effects of proppant concentration on friction pressure of a water-base fluid. ........21 Fig. 13. Borehole fluid invasion zones........................................................................................23 Fig. 14. Effects of proppant concentration and porosity on postclosure polymer concentration.25 Fig. 15. Effect of polymer concentration on retained proppant-pack permeability......................26 TABLES Table 1. Comparison Of Nitrogen And Carbon Dioxide..............................................................13



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1 Introductory Summary The fracturing fluid is a critical component of the hydraulic fracturing treatment. The main functions of the fracturing fluid in a propped fracture are to open the fracture and to transport propping agent along the length of the fracture. An acid fracture accomplishes in essence the same goal as a propped fracture, that is, a structure of much greater conductivity in an otherwise much lower permeability medium. The rheological characteristics of the fluid are often considered the most important. However, successful hydraulic fracturing treatments require that the fluids have some other special characteristics. In addition to exhibiting the proper viscosity in the fracture, the following characteristics are desirable. • The fluid should be compatible with rock composition and formation fluids. •



The fluid should exhibit low friction pressure during pumping.



•



The fluid should provide good fluid-loss control.



•



The fluid should break and clean up rapidly after pumping.



•



The fluid should be as economical as possible.



Since the reservoirs to be stimulated vary markedly in terms of temperature, permeability, rock composition, and pore pressure, many different types of fluids have been developed to provide the characteristics described above. The following classes of fluids are available. • linear water-base fluids •



crosslinked water-base fluids



•



crosslinked oil-base fluids



•



multiphase fluids (foams, polyemulsions, and energized fluids)



•



acidic fluids.



Water-base fluids are used in approximately 70% of all fracturing treatments. Oilbase fluids account for 5%. Multiphase fluids and acid-base fluids are used in approximately 25% of all fracturing treatments. Additives are often added to the fracturing fluid for a variety of reasons. Some of the more important are — to enhance the viscosity at high temperature, to break the viscosity at low temperature, and to help control leakoff of the fluid to the formation. Fracturing fluid components, additives, and additive selection are discussed in Appendix C Additives.



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2 Water-Base Fluids Water-base fluids are the most widely used fracturing fluids because of their low cost, high performance, and ease of handling. Potential problems with water-base fluids are damage to highly water-sensitive formations and proppant-pack damage caused by concentrated polymer. 2.1 Polymers Polymers are water-soluble, high-molecular-weight molecules that can be added to water to make a viscosified solution capable of suspending propping agents. 2.1.1 Guar Gum Guar is a long-chain polymer composed of mannose and galactose sugars. Polymers composed of sugar units are called polysaccharides. The guar polymer has a very high affinity for water. When the polymer is added to water, guar particles "swell" and "hydrate," which means the polymer molecules become associated with many water molecules and unfold and extend out into the solution. The guar solution on the molecular level can be pictured as long, bloated strands suspended in water. The strands tend to overlap and hinder motion, which causes an increase in the viscosity of the solution. The structure of the guar molecule is usually represented as in Fig. 1. The thought for many years was that guar consisted of a mannose backbone with galactose side chains on every other mannose unit (one galactose unit to two mannose units). The galactose and mannose sugars differ in the orientation of the OH groups on the ring. Recent studies indicate that the arrangement of galactose units may be more random, with galactose appearing on two or three consecutive mannose units. Also, the ratio of mannose to galactose may range from 1.6:1 to 1.8:1 instead of 2:1 as indicated in Fig. 1.



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Fig. 1. The structure of guar. 2.1.2 Hydroxypropylguar Guar gum comes from the endosperm of guar beans. The process used to produce guar powder does not completely separate the guar from other plant materials, which are not soluble in water. Consequently, as much as 10% of the guar powder will not dissolve. Guar can be derivatized with propylene oxide to produce hydroxypropylguar (HPG). The reaction changes some of the –OH sites to –O –CH2 –CHOH –CH3. The structure of the HPG molecule is shown in Fig. 2. The additional processing and washing removes much of the plant material from the polymer, so HPG typically contains only about 2 to 4% insoluble residue. It has generally been considered to be less damaging to the formation face and proppant pack than guar, although recent studies have indicated that guar and HPG cause about the same degree of pack damage. Hydroxypropylguar substitution makes HPG more stable at an elevated temperature than guar; therefore, HPG is better suited for use in high-temperature wells. The addition of the less-hydrophilic hydroxypropyl substituents also makes the HPG more soluble in alcohol.



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Fig. 2. The structure of HPG. 2.1.3 Hydroxyethylcellulose Hydroxyethylcellulose (HEC) is used when a very clean fluid is desired. These polymers have a backbone composed of glucose sugar units which appears to be similar to the mannose backbone of guar, but there is a significant difference. Guar contains hydroxl pairs which are positioned on the same side of the sugar molecule (cis orientation). In HEC, the –OH groups are on adjacent carbons, but they are on opposite sides of the ring (trans orientation). The cis arrangement is easily crosslinked, while the trans is not. Fig. 3 shows the structure of HEC.



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Fig. 3. The structure of HEC. 2.1.4 Xanthan Xanthan solutions solutions suspend cellulose xanthan.



is a biopolymer, produced metabolically by a microorganism. Xanthan behave as power-law fluids even at very low shear rates, while HPG become Newtonian. At shear rates less that 10 sec-1, xanthan solutions proppants better than HPG. Xanthan is more expensive than guar or derivatives and is used less frequently. Fig. 4 shows the structure of



Fig. 4. The structure of Xanthan. DOWELL CONFIDENTIAL



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2.1.5 Carboxymethylhydroxypropylguar Carboxymethylhydroxypropylguar (CMHPG) is a "double derivatized" guar that contains the hydroxypropyl functionality of HPG as well as a carboxylic acid substituent. CMHPG is crosslinked with aluminum or zirconium complexes. 2.2 Crosslinkers Polymers produce viscous solutions at ambient temperature; however, as the temperature increases, these solutions thin significantly. The polymer concentration can be increased to offset the thermal effects, but this approach is expensive and damaging. Instead, crosslinking agents are used to dramatically increase the effective molecular weight of the polymer by binding polymer chains, resulting in high fluid viscosities at relatively low polymer concentrations. Inorganic species such as borate salts and organometallic complexes react with guar and HPG through the cis-OH pairs. When the polymer solution is concentrated enough that the molecules overlap (for HPG, at least 0.25% wt/wt), the complex can react with an overlapping polymer so that the two are linked together. A species is created that has two times the molecular weight of the polymer alone. Because each polymer chain contains many cis-hydroxyls, the polymer can be crosslinked at more than one site. Very high-molecular-weight networks develop, especially under static conditions, resulting in highly viscous solutions. 2.2.1 Borate Crosslinker Boric acid and borate salts are used to produce crosslinked fluids with guar and HPG that are stable to 325°F (163°C). At a pH value greater than 8, an extremely viscous fluid forms in a matter of seconds. A high pH value is required for crosslinked fluid stability, with a pH value of 9 to 12 as optimum. Viscosity control of borate-crosslinked fluids is achieved by adjusting polymer concentration or crosslinker concentration. Thermal stability of borate-crosslinked fluids is achieved with delayed activator variance and pH control. A borate-crosslinked fluid will thin when sheared or heated, but will return to its original state after shear or heat is removed. The borate crosslink is reversible; crosslinks form and then break, only to form again. The borate crosslinking mechanism is shown in Fig. 5.



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Fig. 5. Borate crosslinking mechanism. 2.2.2 Organometallic Crosslinkers Organometallic crosslinkers were developed for fracturing high-temperature reservoirs. Titanium and zirconium complexes are used because of their affinity for reacting with oxygen functionalities (cis-OH), stable +4 oxidation states, and low toxicity. The upper temperature limit for organometallic-crosslinked fluids is approximately 350°F (177°C). The stability of the polymer backbone, rather than of the polymer-metal ion bond is the limiting factor. A well with a BHST greater than 400°F (204°C) can be fractured with these fluids if the treatment is designed to provide adequate cooldown. The organometallic-polymer bond is very sensitive to shear. High shear irreversibly degrades organometallic-crosslinked fluid. Unlike the borate crosslinker, once the bond between the organometallic crosslinker and polymer is broken, it does not reform. Crosslinking occurring in a high-shear region is not desirable because an irreversible loss of viscosity results. 2.2.3 Crosslink Rate Crosslinking is a chemical reaction; chemical reaction kinetics apply. The factors affecting crosslink rate (change in viscosity or molecular weight with time) are: • fluid temperature •



fluid pH value



•



shear conditions



•



crosslinker type



•



the presence of competing organic molecules (ligands).



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For example, increasing the temperature or the pH value will usually accelerate the crosslinking reaction. Fortunately, some of these parameters can be controlled to slow down the crosslinking reaction so that it does not occur in the high-shear region (generally 500 to 1,500 sec-1) of the tubulars. Ideally, the crosslinking reaction should occur in the low-shear region (generally 10 to 200 sec-1) of the fracture. There are benefits to delaying the crosslink reaction. These are: • better long-term fluid stability at elevated temperatures •



minimized shear degradation of the fluid



•



reduced pipe friction pressure which permits higher injection rates and reduces horsepower requirements.



Ideally, the crosslink time should be equivalent to the tubing residence time and viscosity should be building as the fluid leaves the tubulars. This is not likely to occur, unless there is a rapid and significant temperature change at this point (physically improbable due to heat transfer and subsequent temperature equilibrization). Practically, a sort of balancing act may be required, the objective being to maximize in-situ fluid viscosity as near the wellbore as possible. This will maintain adequate proppant transport at this critical position in order to minimize proppant banking. The practical solution may come by allowing a certain degree of "sacrificial" crosslinking to occur in the tubulars, such that the reaction is proceeding as the fluid enters the fracture, enhancing proppant transport early near the wellbore, and accepting loss of some long-term-viscosity potential. 2.2.3.1 YF100 and YF200 Fluids The YF*100 and YF200 fluids use a borate crosslinker. Crosslink rate is manipulated by varying the concentration of an activator solution which slowly raises the fluid pH value. 2.2.3.2 YF300 and YF400 Fluids The YF300 and YF400 fluids use a titanate crosslinker. Crosslink rate is controlled by competition for the metal ion between the polymer and a ligand. A competing ligand is added to effect a delay. The YF300 and YF400 fluids are low-pH fluids designed to be used as the liquid phase in carbon dioxide foams or as a base fluid energized with carbon dioxide. 2.2.3.3 YF500 and YF600 Fluids The YF500 and YF600 fluids may be delayed by using a DUO-VIS system; a dual crosslinker system in which a fast and a slow crosslinker are used in combination. The fast crosslinker (a borate crosslinker) ensures that there is adequate viscosity at the perforations. The slow crosslinker (a zirconate crosslinker), which is accelerated *



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by the heating of the fluid in the fracture, ensures there will be a viscous, temperature-stable fluid in the fracture.



3 Crosslinked Oil-Base Fluids Aluminum phosphate ester chemistry is used to viscosify oil for fracturing purposes. Interactions between the aluminum complexes and phosphate ester molecules produce a long polymer chain (Fig. 6).



Fig. 6. The structure of aluminum phosphate ester chain. The structure of aluminum phosphate ester chain. The R groups in Fig. 6 are hydrocarbon chains that must be soluble in the oil to be gelled. The soluble R groups keep the aluminum phosphate ester polymer in solution. Generally, the R groups are hydrocarbon chains containing 1 to 18 carbon atoms. The R groups have a high affinity for oils such as kerosene and diesel which are comprised of 12carbon to 18-carbon (and somewhat higher) chains. Crude oils are composed of a larger number of different organic compounds and may contain paraffins and asphaltenes. Some of the high-molecular-weight compounds, especially the paraffins and asphaltenes, are not compatible with the aluminum phosphate ester gelling system. Many crude oils can be gelled, but should be tested prior to use. The viscosity of the standard aluminum phosphate ester fluid is controlled by varying the quantities of aluminum compound and phosphate ester. High-temperature performance can be enhanced by increasing the polymer concentration; however, this can result in very high surface viscosity, making suction out of tanks difficult. The Fracturing Materials Manual—Fluids provides additional information on crosslinked oil-base fluids.



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3.1 YF"GO"III and YF"GO"IV Fluids YF"GO"III can be batch-mixed or continuously-mixed. The temperature range of YF"GO"III is 100° to 200°F (38° to 93°C). YF"GO"IV is batch-mixed. The temperature range of YF"GO"IV is 150° to 300°F (65° to 150°C).



4 Multiphase Fluids The properties of standard water-base or oil-base fluids can be enhanced by incorporating a second phase into the fluid. Foams and energized fluids are created by adding gas (usually nitrogen or carbon dioxide) to water- or oil-base fluids. Emulsions are created by mixing oil, water or acid, and an emulsifying agent. 4.1 Foams A foam fracturing fluid is a stable emulsion composed of a liquid (external or continuous) phase surrounding a gas (internal, dispersed or non-continuous) phase and a surfactant (foaming agent). The infrastructure of a foam fluid is composed entirely of bubbles. The liquid phase creates the surface structure of the individual bubbles. Bubble surfaces contact other bubble surfaces with no free fluid separating the bubbles. The gas phase is 52 to 96% (vol/vol). A discussion of foam fracturing fluids is provided in Foam Fracturing. 4.2 Energized Fluids The primary reason for energizing a fracturing fluid is to eliminate the need for swabbing or pumping. The infrastructure of an energized fluid matrix is composed of a liquid with bubbles of gas dispersed throughout. A volume of liquid always separates the individual bubbles. The gas phase is less than 52% (vol/vol). The compressed gas functions in two ways. 1.



When the pressure is released at the wellhead, expansion towards the wellbore forces the fluid from the formation.



2.



The presence of gas in the liquid reduces the weight of the fluid column so that normal reservoir drive is sufficient to unload fluids from the well.



Reservoir pressure and permeability influence the fluid flowback after a fracturing treatment. Flowback in a low-pressure reservoir must result almost entirely from the effect of compressed gas injected with the fluid. Low reservoir pressure combined with high permeability allows the gas to expand rapidly into the reservoir. When this condition exists, localized pressure cannot be maintained long enough to overcome hydrostatic fluid pressure in the well. The result is ineffective flowback. Long shut-in times allow the gas to segregate from the liquid and should be avoided. A localized increase in matrix pore pressure temporarily exists after a fracturing treatment. The time required for this pressure to dissipate and reach equilibrium DOWELL CONFIDENTIAL



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with the reservoir will vary from a few minutes to a few days, depending on the properties of the reservoir and reservoir fluids. This additional pore pressure is available to help return the fracturing fluid to the surface. The energy in the form of compressed gas can be used for more effective return of the fracturing fluid. 4.2.1 The Gas Phase Nitrogen and carbon dioxide are the gases most commonly used in foamed and energized fluids. Formation characteristics, fluid compatibility, and economics are major factors that are considered during the decision-making process. Nitrogen is an inert gas, and is the most frequently used because it is versatile. Carbon dioxide is more soluble in water than nitrogen so more carbon dioxide is required to saturate the liquid and create the foam. Carbon dioxide is extremely soluble in oil. StableOil-Foams normally use nitrogen as the gas phase when the foam quality is greater then 50%. Table 1 provides a comparison of nitrogen and carbon dioxide.



Table 1. Comparison Of Nitrogen And Carbon Dioxide Property



Nitrogen



Carbon Dioxide



Hydrostatic Head Reactive Solubility in Water Solubility in Oil Surface Tension Reduction Compressibility Temperature



Low Inert Low Low None High



High Yes Moderate High Good Low



100°F (38°C)



20° to 40°F (-7° to 4°C)



In certain applications, carbon dioxide may have certain advantages: • greater hydrostatic pressure (carbon dioxide is more dense than nitrogen) resulting in lower treating pressure •



more expansion during flowback (aids in total fluid recovery)



•



may prevent or remove water blocks.



Fluids that are saturated with carbon dioxide have low interfacial tension which reduces capillary pressure and damage. The solubilized portion of carbon dioxide reduces the interfacial tension of the fracturing fluid to levels as low as those obtainable by many surfactants. Carbon dioxide has an advantage in that the carbon dioxide is soluble in the water whereas the surfactant may loose its efficiency by absorbing onto the rock surfaces. Carbon dioxide also reduces the viscosity of formation oil. Care must be taken to ensure that the carbon dioxide and the relatively large proportion of surfactants pumped into the formation do not create emulsions that could damage the permeability and reduce productivity. DOWELL CONFIDENTIAL



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Carbon dioxide, unlike nitrogen, is not compatible with all liquid phases. Carbon dioxide is not recommended in the following fluids. • YF100, YF100D, YF100HTD, YF200, YF200D, YF500HT, YF600LT, YF600HT, and YF600UT. Carbon dioxide will interfere with the crosslinking mechanism by lowering the fluid pH value. Carbon dioxide tends to accelerate the viscosity development in YF"GO" fluids. At volumes greater than 30%, carbon dioxide reduces the stability of the fluid and may prematurely break the fluid. Carbon dioxide is easily dispersed in the YF300LPH and YF400LPH fluids. The pH buffer contained in the crosslinker solution maintains a constant fluid pH value of approximately 4, which simulates a saturated carbon dioxide environment. Consistent fluid performance is ensured despite variations in the carbon dioxide concentration or complete loss of carbon dioxide during job execution. Carbon dioxide is pumped at the wellhead in liquid form. The critical temperature (triple point) of carbon dioxide is approximately 88°F (31°C). Carbon dioxide is a supercritical fluid commonly referred to as a gas at temperatures greater than 88°F (31°C). The transition from liquid to supercritical fluid does not affect the physical properties of either the carbon dioxide or the foam provided the treating pressure is greater than 1,080 psi, the critical pressure of the carbon dioxide. 4.3 Emulsions An emulsion is a dispersion of two immiscible phases such as oil in water, or water in oil, stabilized with a surfactant. Emulsion fracturing fluids are very viscous solutions with good proppant transport and fluid-loss properties. The greater the percentage of internal phase (to a point of inversion), the more resistance there is to droplet movement, resulting in higher viscosity. The most common emulsion (Super Sandfrac K-1), termed "polyemulsion," is a water-external emulsion where viscosified water is the continuous phase and oil is the discontinuous phase. The fluid is 67% oil and 33% water, stabilized with an emulsifier. Viscosifying the aqueous phase improves the polyemulsion stability and significantly reduces friction pressure during pumping. The polymer concentration used is generally 20 to 40 lbm/1000 gal in the aqueous phase, so the polyemulsion contains only one-sixth to one-third as much polymer as a typical water-base fracturing fluid. Since so little polymer is used, a polyemulsion will result in less conductivity damage (than a water-base fluid) and will clean up rapidly. Viscosity reduction (break) of the polyemulsion occurs when the emulsifier is absorbed by the formation rock. The viscosity and stability of the polyemulsion are dependent on the oil droplet size. The droplet size decreases as the shear rate increases (rather than shear time), so the shear rate at the mixing pump must be maximized. This can be accomplished by operating the pump at the highest speed possible. Recirculating the emulsion increases the shear time rather than the shear rate and is not very effective. DOWELL CONFIDENTIAL



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In comparison to a water-base fluid the disadvantages of a polyemulsion are: • higher friction pressure •



higher fluid cost (If diesel is used. If lease crude is used, fluid cost is considered low)



•



significant thinning as the BHST increases.



The Fracturing Materials Manua — Fluids provides additional information on emulsions.



5 Acidic Fluids An acidic fluid, usually hydrochloric acid, may be used in carbonate formations as a fracturing fluid. Portions of the fracture face are dissolved as the acid flows along the fracture. Since flowing acid tends to etch in a nonuniform manner, conductive channels are created which usually remain when the fracture closes. The effective length of the fracture is determined by the following: • acid volume •



acid reaction rate



•



acid fluid loss.



The effectiveness of the acid fracturing treatment is largely determined by the length of the etched fracture. While the use of acid as a fracturing fluid eliminates many problems inherent in propped fracturing, it introduces problems of a different nature. The effective length of a propped fracture is limited by the distance the propping agent can be transported in the fracture. Similarly, the effective length of an acidized fracture is limited by the distance acid travels along the fracture before spending. The major barrier to effective fracture penetration by acid is excessive fluid loss. Fluid loss is a greater problem when using acid and is very difficult to control. The constant erosion of fracture faces while pumping makes deposition of an effective filter-cake barrier difficult. In addition, acid leakoff is nonuniform and can result in wormholes and enlargement of natural fractures. This greatly increases the effective area from which leakoff occurs and makes fluid-loss control extremely difficult. The Fracturing Materials Manual — Fluids provides additional information on acid fracturing fluids. A discussion of acid fracturing techniques is provided in Acid Fracturing.



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6 Fracturing Fluid Characterization 6.1 Rheology Rheology is the science of the deformation and flow of matter. For fracturing fluids, the important variable is the apparent viscosity of the fluid as a function of shear, temperature, and time. These relationships are commonly determined for fluids (without proppant) in rotational concentric cylinder, capillary, or pipe rheometers. Very little laboratory rheological testing of fluids containing proppant is done because of the difficulties in evaluating the rheology of these fluids. 6.1.1 Shear and Temperature A fracturing fluid experiences wide variations in shear and temperature during a hydraulic fracturing treatment. High shear is experienced by the fluid during pumping through the tubulars and perforations. Once in the fracture, the shear on the fluid is significantly less, but fluid temperature increases until it eventually reaches formation temperature. 6.1.2 Shear Rate Shear of fluid in laminar flow can be thought of as a process in which infinitely thin, parallel planes slide over each other. Shear rate is defined as the velocity difference between the planes divided by the distance between the planes. The usual rate of shear reported in viscometric experiments is the value at the wall of the instrument. 6.1.3 Shear Stress Shear stress is the shearing force per unit area of surface. In most measurements, the shear stress is determined by measuring the torque exerted on a measurement bob or by the pressure drop across a tube. 6.1.4 Apparent Viscosity Apparent viscosity is the shear-stress to shear-rate ratio. The apparent viscosity can be determined using Eq. 1. µa =



47,880 K ′ γ 1− n ′



Where:



µa = apparent viscosity (cp) n' 2 K' = consistency coefficient (lbf-secn ;/ft )



γ = shear rate (sec-1) n' = power-law exponent (dimensionless).



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6.1.5 Newtonian Fluids Newtonian behavior implies that fluids have a constant viscosity at all shear rates. Water, low-viscosity oils, and gases are examples of fluids that exhibit this behavior. Fracturing fluids exhibit predominantly non-Newtonian behavior. This means that the apparent viscosity of the fluid is dependent on the shear that the fluid is experiencing at the moment of interest. A fracturing fluid may have considerably different apparent viscosities, depending on the shear that is exerted on the fluid. This nonNewtonian behavior plays a significant role in the tubular and fracture friction pressures, and in the proppant-transport capabilities of the fluid. 6.1.6 Non-Newtonian Fluids The power-law model is used to represent behavior of non-Newtonian fluids. A straight line is predicted on a log-log plot of shear stress versus shear rate. The slope of the line is denoted as n' (generally less than one) and is termed the "powerlaw exponent." The stress at a shear rate of unity is denoted as K' and is termed the "consistency coefficient." The n′ and K′ values of fracturing fluids change with increasing time and temperature; n' tends toward unity and K' decreases. Fig. 7, Fig. 8, Fig. 9, and Fig. 10 show typical rheology data for a crosslinked waterbase fluid containing polymer at 40 lbm/1000 gal. The data is expressed in terms of n', K', and apparent viscosities at 40 sec-1 and 170 sec-1. Note the reduction in K' and viscosity with time and temperature.



Fig. 7. Power-law exponent of a 40 lbm/1000 gal crosslinked water-base fluid.



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Fig. 8. Consistency coefficient of a 40 lbm/1000 gal crosslinked water-base fluid.



Fig. 9. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 40 sec-1.



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Fig. 10. Apparent viscosity of a 40 lbm/1000 gal crosslinked water-base fluid at 170 sec-1. 6.2 Slurry Rheology Fluids containing proppant account for 20 to 80% of the total volume of a fracturing treatment, yet very little rheological data exists on these slurries. Determining the rheological properties of fracturing fluids containing proppant as a function of fluid composition, flow geometry, temperature, time, and proppant size, density, and concentration is a considerable problem. The majority of instruments used to determine rheological properties of fluids without proppant is unusable for these studies because their geometries will not accommodate the large particles and concentrations. Fig. 11 shows the affects of proppant on the slurry viscosity of a Newtonian fluid. Corresponding data for power-law fluids have not been developed.



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Fig. 11. The effects of proppant on slurry viscosity of a Newtonian fluid.



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The friction pressure of fluid containing proppant will increase as proppant concentration increases. Fig. 12 shows the effect of proppant concentration on friction pressures of a water-base fluid containing polymer at 40 lbm/1000 gal. in 2.875 in. tubing. Fig. 12 is for illustrative purposes only.



Fig. 12. The effects of proppant concentration on friction pressure of a water-base fluid. 6.3 Proppant Transport The purpose of propping agents in a hydraulic fracturing treatment is to hold the fracture open and provide a permeable path for fluid flow into the wellbore. The improvement of well productivity depends on the final propped fracture geometry and fracture conductivity. Propped fracture geometry is determined by the settling rates of the proppant in the fracturing fluid during injection and closure. High proppant-settling velocities during the treatment may result in the formation of a proppant bank at the bottom of the fracture. This will increase the risk of proppant bridging, high pumping pressure, and near-wellbore screenout. Low settling velocities result in more evenly distributed



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proppant over the total fracture height and the greatest potential for productivity improvement. Most fracturing fluids are non-Newtonian with fluid viscosity decreasing as shear increases. The most important variables affecting proppant settling are the nonNewtonian characteristics of the fluid, wall effects, and proppant concentration. As shear rates approach very low or very high values, limiting values of apparent viscosity are reached. In actual treatments, high shear-limiting viscosity values are approached in the fracture. However, at the center of the fracture channel, the shear rate is zero and the fluid viscosity approaches the value for zero-shear viscosity. Low shear viscosity plays an important role in proppant transport during flow conditions. The settling velocity equation is a modification of Stoke's law (Eq. 2). g∆pd p2 g∆pd p2  ut  + ut =   18 µ o 18 K ′  d p 



1− n ′



(2)



Where: 2



g = gravity acceleration (ft/sec ) ∆p = density differential of proppant and fluid (lbm/ft3) dp = particle diameter (in.) µo = zero shear viscosity (cp) K' = consistency coefficient (lbf-secn′/ft2) ut = terminal settling velocity (ft/sec) n' = power law exponent (dimensionless). 6.4 Fluid-Loss Fluid loss to the formation is a filtration process which is controlled by the following parameters: • fracturing fluid composition •



flow rate and pressure



•



reservoir properties (such as permeability, porosity, pressure and fluid saturation)



•



the presence of microfractures, macrofractures, or faults.



Prior to the fracturing treatment, the formation contains a number of fluids (hydrocarbons, water) with different flow properties. When the fracturing fluid penetrates the formation, there may be three zones (refer to Fig.13): • a filter cake with varying thickness (R1) •



a zone invaded by the filtrate (R2)



•



a region with the reservoir fluids only (R3).



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Fig. 13. Borehole fluid invasion zones. In the first region (R1), polymer and fluid-loss additive particles are deposited and form a filter cake. The rate of fluid flow through the cake is governed by the WallBuilding Coefficient (Cw). The second region (R2) contains the filtrate. The filtrate flow rate is governed by Darcy's law. Derived from Darcy's law is the Viscosity Control Coefficient (Cv). The third region (R3) has the flow of the native fluids alone. The compressibility, viscosity, and relative permeability to those reservoir fluids affect the rate of leakoff of the fracturing fluid. Fluid loss in this region is governed by the Compressibility Coefficient (Cc). A complete discussion of fluid loss is provided in Appendix E — Fluid Loss. 6.5 Conductivity Damage from Fracturing Fluids Polymer that is concentrated within the proppant pack due to fluid leakoff and volume reduction during fracture closure is the primary cause of proppant-pack damage. The polymers used in fracturing fluids are too large to enter the pore throats of most reservoir rocks and therefore become very concentrated. The severity of damage increases as the polymer concentration increases and is strongly dependent on the type of crosslinker. The first point is emphasized by the fact that foams of either nitrogen or carbon dioxide as the gas phase clean up much better than typical water-base fracturing fluids. The borate-crosslinked fluids are less damaging than the organometallic-crosslinked fluids. Breakers will reduce the severity of proppant-pack damage caused by concentrated polymers. The amount of retained permeability that can be achieved is directly related to the breaker concentration; increasing the breaker concentration will increase the fracture conductivity.



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Polymer concentration and crosslinker type are even more important than polymer type when considering the effect of fracturing fluid on proppant-pack conductivity. During the late 1970s, derivatives of base polymers were developed to make a "cleaner" polymer. Natural guars were derivatized with propylene oxide to create HPG. Later, HPG polymers were further derivatized to CMHPG. Recent studies indicate little or no benefit in using these more-costly polymers based on their proppant-pack permeability damage. Optimization of fracture conductivity (kfw) and dimensionless fracture conductivity (Cfd) can only be accomplished by understanding proppant-pack damage and its effects on in-situ fracture permeability. The in-situ fracture permeability (kf) has long been recognized as one of the most limiting factors controlling well productivity. The in-situ fracture permeability is usually only a fraction of the original clean proppant permeability value. 6.5.1 The Effect of Water-Base Fracturing Fluids on Retained Permeability Postclosure polymer concentrations of 200 to 1000 lbm/1000 gal are common and result in reduced fracture permeability, and therefore fracture conductivity. The parameters known to affect the degree of proppant-pack damage are: • postclosure polymer concentration •



initial polymer concentration (surface)



•



crosslinker type



•



fracturing fluid temperature



•



breaker concentration.



Postclosure polymer concentration factors may be approximated (assuming that all the polymer remains within the proppant pack), using Eq. 3. p′ =



ps ( 1 − φ / 100) × cs (φ / 100)



(3)



Where: p' = polymer concentration factor (dimensionless) ps = absolute proppant density (lbm/gal) cs = average proppant concentration in fluid (including pad) (PPA) φ = proppant-pack porosity (%). The final polymer concentration is then calculated by multiplying the initial polymer concentration by the polymer concentration factor. An approximation for polymer concentration factors is represented graphically in Fig. 14 for a 20/40-mesh Northern White Sand proppant pack. The fracture width is reduced as closure stress increases, which reduces the pore volume to proppant DOWELL CONFIDENTIAL



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volume ratio within the fracture, and therefore reduces the proppant-pack porosity. For example, if 50,000 gal of a 40-lbm/1000 gal borate-crosslinked fracturing fluid were pumped to place 200,000 lbm of 20/40 proppant, the average proppant concentration would be 4.0 lbm/gal. Assuming a proppant-pack porosity of 33.5%, Fig. 14 indicates the polymer concentration factor is approximately 11. Therefore, the postclosure polymer concentration within the proppant pack would be an average of approximately 11 times the initial polymer concentration, or 440 lbm/1000 gal. Polymer concentrations of this magnitude, unless thoroughly degraded, are difficult to displace, causing significant damage to the proppant-pack permeability.



Fig. 14. Effects of proppant concentration and porosity on postclosure polymer concentration. The effect of polymer concentration on the retained proppant-pack permeability is demonstrated in for linear, borate-crosslinked, and organometallic-crosslinked fluids. The severity of proppant-pack damage increases as polymer concentration increases and is strongly affected by the crosslinker type. The linear fluid exhibits only 12% retained permeability at a polymer concentration of 400 lbm/1000 gal. The crosslinked fluids impair the retained permeability to an even greater degree than the noncrosslinked fluid. At the same polymer concentration of 400 lbm/1000 gal, the borate-crosslinked fluid exhibited less than 5% retained permeability. Fig. 15 also shows that at any given polymer concentration, the organometallic-crosslinked fluid is more damaging than the borate-crosslinked fluid. The data presented in Fig. 15



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are considered to be the best case because a proppant concentration of 2 lbm/ft2 is rarely achieved.



Fig. 15. Effect of polymer concentration on retained proppant-pack permeability.



7 Fluid Selection The selection of a fracturing fluid involves many compromises imposed by economical and practical considerations. Guidelines for fracturing fluid selection are provided in Treatment Design.



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APPENDIX C - ADDITIVES 1 Introductory Summary............................................................................................................. 2 2 Fracturing Fluid Components................................................................................................. 2 2.1 Activators ............................................................................................................................. 3 2.2 Buffers.................................................................................................................................. 3 2.3 Crosslinkers ......................................................................................................................... 3 2.4 Emulsifiers ........................................................................................................................... 3 2.5 Foaming Agents................................................................................................................... 4 2.6 Polymers .............................................................................................................................. 4 2.7 Potassium Chloride .............................................................................................................. 4 3 Fracturing Fluid Additives ...................................................................................................... 4 3.1 Bactericides ......................................................................................................................... 4 3.2 Breakers............................................................................................................................... 5 3.2.1 Breakers for Water-Base Fluids.................................................................................. 6 3.2.1.1 Enzyme Breakers............................................................................................. 6 3.2.1.2 Oxidative Breakers........................................................................................... 6 3.3 Clay Stabilizers .................................................................................................................... 9 3.3.1 Clay Types.................................................................................................................. 9 3.3.2 Clay Control Methods ............................................................................................... 12 3.3.2.1 Ionic Neutralization ........................................................................................ 12 3.3.2.2 Organic Barrier .............................................................................................. 13 3.3.2.3 Particle Fusion ............................................................................................... 13 3.4 Fluid-Loss Additives ........................................................................................................... 13 3.5 Friction Reducers............................................................................................................... 14 3.6 Temperature Stabilizers..................................................................................................... 15 3.7 Surfactants......................................................................................................................... 17 3.7.1 Fluorocarbon Surfactants ......................................................................................... 22 3.7.2 Surfactant Selection.................................................................................................. 22 3.8 Nonemulsifying Agents ...................................................................................................... 23 DOWELL CONFIDENTIAL



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3.8.1 Nonemulsifying Agent Selection................................................................................23 4 Additive Selection ..................................................................................................................25 FIGURES Fig. 1. Apparent viscosity of 40 lbm/1000 gal crosslinked fluids with methanol and sodium thiosulfate stabilizers. ......................................................................................................16 Fig. 2. Apparent viscosity of a 50 lbm/1000 gal crosslinked fluid containing sodium thiosulfate and a 60 lbm/1000 gal crosslinked fluid containing methanol. ........................................16 Fig. 3. Surfactant orientation. .....................................................................................................18 Fig. 4. The wettability of oil/water/rock. ......................................................................................20 TABLES Table 1. Table 2. Table 3. Table 4. Table 5. Table 6.



Properties Of Common Dowell Surfactants ..................................................................21 The Effects of Wettability Change ................................................................................21 Summary of Surfactant Action on Mineral Surfaces .....................................................22 Properties Of Common Dowell Nonemulsifying Agents ...............................................24 Additive Recommendation Guide .................................................................................25 Additive Selection Guide ..............................................................................................26



1 Introductory Summary A fracturing fluid is not simply a viscosified liquid, such as water and guar polymer or diesel oil and aluminum phosphate ester polymer. Fracturing fluids are complex systems containing various additives that are used to modify fluid behavior. Fracturing fluids commonly contain five or more additives.



2 Fracturing Fluid Components Certain materials are not considered additives because they are required to make the base fluid. These are: • activators •



buffers



•



crosslinkers



•



emulsifiers



•



foaming agents



•



polymers



•



potassium chloride (KCl).



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2.1 Activators Activators are strong bases that enable crosslinking by raising the pH value in the borate-crosslinked fluids. 2.2 Buffers Buffers are weak acids or bases that are added to water-base fracturing fluids to maintain a desired pH value. The buffers will maintain the pH value at a desired level even if an extraneous acid or base is introduced (for example, through contaminated water or proppant). This is especially important when using enzyme breakers. The optimum pH range for enzyme breakers is 3.5 to 5.0. Enzyme breakers are deactivated when the fluid pH value is greater than 9.0. Buffers are also used to maintain the proper pH value for crosslinked fluids. This is important because crosslinking rate and polymer stability are affected by the fluid pH value. Crosslinked fluids are generally formulated to work best in a narrow pH range (±0.25 units from the optimum). Guar and HPG can be crosslinked at a pH range of 3 to 10, depending on the type of crosslinker used. Buffers also promote hydration of the polymer. For example, guar and hydroxypropylguar (HPG) are treated to be dispersible and nonhydrating at a high pH value. Initially, the water pH value should be high to allow polymer dispersion. After the polymer is dispersed, the water pH should be lowered to promote hydration. The pH value can be lowered by adding an acidic buffer after the polymer is dispersed. Combining a slowly-soluble acid with the dry polymer is another approach. polymer disperses before the acid can dissolve and lower the pH value.



The



Acetic acid, adipic acid, formic acid, and fumaric acid are acids used as buffers. Sodium carbonate and sodium bicarbonate are bases used as buffers. All Dowell gelling agents contain buffers. 2.3 Crosslinkers Crosslinking agents enable the individual polymeric molecules to form a complex network of entangled polymer with the associated hydrated water. This results in higher molecular weight (higher viscosity) and less freedom of random motion (greater resistance to deformation) for the solvent and polymer. Not only does crosslinking result in higher viscosity, it lends stability to viscosity loss with time at elevated temperatures.



Appendix B — Fracturing Fluids provides additional information for crosslinkers. 2.4 Emulsifiers Emulsifiers are used to create emulsion-base fracturing fluids. The most common fluid, Super Sandfrac K-1, is composed of 67% hydrocarbon internal phase and 33% viscosified water external phase. DOWELL CONFIDENTIAL



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2.5 Foaming Agents Foaming agents are used to create a stable emulsion composed of a liquid (external or continuous) phase surrounding a gas (internal, dispersed, or noncontinuous) phase. 2.6 Polymers Polymers (gelling agents) are high-molecular-weight molecules that can be added to a base fluid to make a viscosified solution capable of suspending propping agents.



Appendix B — Fracturing Fluids provides additional polymer information. 2.7 Potassium Chloride Aqueous solutions of 2% (wt/wt) KCl are routinely used as the base liquid in fracturing fluids. KCl is added to the water to keep negatively charged clay platelets in place by surrounding them with an electrically neutral fluid containing positive ions. KCl is used more often than sodium chloride (NaCl) or ammonium chloride (NH4Cl) because the single charge density and small size of the potassium ion better stabilizes clays against invasion of water and, consequently, prevents swelling. KCl helps maintain the chemical environment of the clay particles, but it does not provide permanent stabilization.



3 Fracturing Fluid Additives Fracturing treatment optimization involves selecting the best base fluid system together with special additives required for the specific reservoir and well. Additives include: • bactericides •



breakers



•



clay stabilizers



•



fluid-loss additives



•



friction reducers



•



temperature stabilizers



•



surfactants



•



nonemulsifying agents.



3.1 Bactericides The polymers used in water-base fracturing fluids are excellent food sources for bacteria. Bactericides are added to water-base fracturing fluids to prevent bacterial degradation of the polymer and to protect the formation from bacterial growth. Common practice is to add a bactericide to the frac tanks before water is added to DOWELL CONFIDENTIAL



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ensure that the bacterial enzyme count remains low. No water-base fracturing fluid should be pumped into a well without some type of bactericide present. Bactericides are unnecessary in oil-base fracturing fluids. Bacteria may be aerobic or anaerobic. Aerobic bacteria require oxygen for survival. Anaerobic bacteria can exist in the absence of oxygen.



Aerobic Bacteria Aerobic bacteria produce enzymes that degrade the polymers used in water-base fracturing fluids resulting in a viscosity loss and premature break of the fluid.



Anaerobic Bacteria Anaerobic bacteria, introduced by the fracturing fluid, can create severe reservoir problems. The bacteria can multiply in such numbers that they reduce permeability and, consequently, damage the formation. Certain types of anaerobic bacteria chemically reduce sulfate ions to produce hydrogen sulfide, creating a safety hazard. Hydrogen sulfide also corrodes tubular goods and production equipment.



Bactericide M76 Bactericide M76 is a quaternary amine that will kill bacteria and deactivate the enzyme. M76 concentrations are dependent on fluid surface temperature and range from 0.5 gal/1000 gal to 1.5 gal/1000 gal.



Dryocide Dryocide will kill bacteria and deactivate the enzyme. concentration of 0.5 lbm/1000 gal.



Dryocide is used at a



Microbiocide M275 Microbiocide M275 is a concentrated isothiazolin compound that is adsorbed onto an inert solid for ease of handling. M275 will kill bacteria but will not effectively deactivate the enzyme. M275 concentrations are dependent on fluid surface temperature and range from 0.3 lbm/1000 gal to 0.6 lbm/1000 gal. 3.2 Breakers Thermal breaking of the polymer backbone generally occurs in wells with bottomhole temperatures greater than 225°F (107°C). A breaker should be added to the fracturing fluid when the bottomhole temperature is less than 225°F (107°C). Breakers are added to fracturing fluids for two reasons. 1.



To reduce the viscosity of the fluid so that the fracturing fluid can be cleaned up quickly following a treatment.



2.



To degrade the fluid and thus reduce proppant-pack conductivity damage.



Breakers perform both these tasks by attacking the backbone of the polymer and reducing its size. The fluid viscosity decreases as the polymer molecular weight decreases. DOWELL CONFIDENTIAL



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Controlling the timing of the breaking process is critical to the success of the fracturing treatment. Once a breaker is added to a fracturing fluid, the degradation process begins immediately. Careful planning must go into the design of breaker schedules. If too much breaker is added early in the treatment, the viscosity required for fluid-loss control and proppant transport may be prematurely lost, resulting in a screenout. If the breaker schedule is not ambitious enough, the molecular chains may not sufficiently degrade, causing the treatment to clean up slowly. Even worse, without sufficient breaker quantities, the fluid may not completely degrade, limiting well production because of proppant-pack damage. The postclosure polymer concentration in the fracture may increase to concentrations greater than 500 lbm/1000 gal because of filtrate loss. The breaker level in this concentrated fracturing fluid decreases as the polymer concentration increases. The breaker is dissolved into the water portion of the slurry and is lost in the fluid leaking off as the fracturing fluid dehydrates. This can result in a damage to the proppant pack which may exceed 90%. Tapered breaker schedules allow much greater quantities of breaker to be added to the fluid while minimizing the risk of excessive degradation. To design the breaker schedule, the time of exposure to bottomhole temperature for each stage of the fracture treatment must be determined. From this, a maximum quantity of breaker can be calculated without risking premature loss of viscosity. Detailed breaker schedule design information is provided in Treatment Design. 3.2.1 Breakers for Water-Base Fluids The breakers currently used in water-base fluids are enzyme breakers and oxidative breakers. 3.2.1.1 Enzyme Breakers Enzyme breakers such as hemicellulase begin to degrade the polymer immediately. These enzymes are similar to those that bacteria use to digest the polymer.



Enzyme Breaker J134L Enzyme Breaker J134L is a low-temperature breaker and is the preferred breaker for low-pH fluids such as those foamed with CO2. The optimum temperature range for J134L is 75° to 130°F (24° to 54°C). It is not effective at temperatures greater than 150°F (66°C). The optimum pH range for J134L is 3.5 to 5.0. In fluids with a pH value greater than 9.0, J134L becomes inactive and should not be used. 3.2.1.2 Oxidative Breakers The most common oxidative breakers are peroxydisulfates. Thermal decomposition of peroxydisulfate produces highly reactive sulfate radicals which attack the polymer backbone. Oxidative breakers are used in applications where the fluid is exposed to DOWELL CONFIDENTIAL



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bottomhole temperatures greater than 125°F (52°C). Sulfate radical generation occurs rapidly at temperatures greater than 125°F (52°C). Thermal decomposition is slow at temperatures less than 125°F (52°C). These breakers can be expanded into lower temperature applications (60° to 125°F [16° to 52°C]) if an amine is concurrently added to catalyze the reaction. Oxidative breakers are effective over a wide pH range (3 to 14) and demonstrate breaking properties superior to enzyme breakers (based on observed proppant-pack permeability reduction). This is especially true when the oxidative breaker reaction is catalyzed by the amine.



Breaker J218 J218 is an ammonium persulfate oxidative breaker. temperature range of 125° to 225°F (52° to 107°C).



J218 is effective in the



In high-temperature wells, J218 can be used in the latter stages to promote rapid degradation of the polymer at the wellbore or near-wellbore area. This is extremely useful where forced-closure techniques are practiced.



EB-Clean J475 Breaker EB-Clean* J475 Breaker is used as component of the CleanFRAC* Service. J475 is a 20/40-mesh material produced by coating (encapsulating) an ammonium persulfate oxidative breaker material (J218) with a water-resistant barrier. Encapsulation of the breaker greatly reduces fracturing fluid exposure to the breaker and enables the use of high concentrations of breaker that without coating, would rapidly reduce the fluid viscosity. Unlike breakers that dissolve in the fracturing fluid (for example, J218 and J134L), J475 will not leak off and be lost to the formation. It remains in the fracture to degrade concentrated polymers. After the fracturing treatment, release of the breaker occurs as reservoir temperature increases and the fracture closes. An upper temperature limit of 180°F (82°C) is supported by laboratory data. J475 is most effective when fluid temperatures are predicted to be less than 180°F (82°C). J475 may rapidly deactivate when fluid temperatures are greater than 180°F (82°C) resulting in minimal conductivity improvement. Field data has indicated positive results using J475 at temperatures greater than 225°F (107°C). Because an upper temperature limit for J475 has not been established during field use, J475 may possibly be used at higher temperatures if positive results have been observed on other fracturing treatments. Some of these results are: • returned fluid had a low viscosity and viscosity did not increase



*



•



cleanup was at least as good as expected



•



production was as good or better than expected.



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EB-Clean LT J479 Breaker J479 is used as part of the CleanFRAC* Service. J479 is a 20/40-mesh material produced by coating (encapsulating) breaker material (J218) with a water-resistant barrier. Encapsulation of the breaker greatly reduces fracturing fluid exposure to the breaker and enables the use of high concentrations of breaker that without coating, would rapidly reduce the fluid viscosity. J479 is used in low-temperature wells where J475 is often not suitable. Release of the breaker occurs gradually with time and is enhanced by low levels of closure stress. J479 is used in conjunction with J318 or J466. J479 is used when fluid temperatures are predicted to be less than 125°F (52°C).



Breaker J481 J481 is an oxidative breaker composed of sodium bromate. J481 is approved only for use with YF*100HTD fluids. The reactiveness (thermal decomposition) of J481 and YF100HTD fluids is strongly dependent on temperature. J481 is effective at temperatures ranging from 200° to 275°F (93° to 135°C).



Liquid Breaker Aid J318 Liquid Breaker Aid J318 is used in conjunction with oxidative breakers when the fluid temperature is less than 125°F (52°C). J318 may be used in the WF100, WF200, YF100 (nondelayed), and YF200 (nondelayed) fluids. The amines in J318 accelerate the generation of sulfate radicals from the oxidative breakers, making it an effective breaker at a low temperature. J318 is a catalyst and not a breaker on its own. The application of the amine breaker aid with the persulfate breaker is patented Dowell technology (U.S. Patent No. 4,250,044, and No. 4,560,486).



Breaker Aid J466 Breaker Aid J466 is used in conjunction with oxidative breakers when the fluid temperature is less than 125°F (52°C). J466 is used in the YF100D and YF200D fluids only. (J318 is not compatible with the YF100D and YF200D fluids. These fluids use a mechanism that slowly raises the fluid pH value and enables delayed crosslinking. J318 is strongly alkaline and will rapidly raise the fluid pH value.)



Breakers for Crosslinked Oil-Base Fluids Breakers for crosslinked oil-base fluids (gelled oils) operate much differently than their water-base counterparts. Most gelled-oil breakers are slowly soluble bases such as lime or bicarbonate and are intended to reverse the reactions between the aluminum complexes and phosphate ester molecules. Gelled oils can be difficult to break at bottomhole temperatures less than 100°F (38°C). The breakers used in gelled oils are: • FIXAFRAC*J59 • *



Breaker J603



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Soda Ash M3.



3.3 Clay Stabilizers Clays are layered particles of aluminum and silicon oxide that are less than four microns in diameter. Clays can swell or migrate (or both), resulting in permeability damage. The damage can occur during drilling, completion, or production of the well. Severity of damage caused by clay swelling and clay migration is dependent on the following parameters: • clay type •



clay content



•



clay distribution



•



pore-size distribution



•



grain-size distribution



•



quantity of cementing materials (for example, calcite, siderite, and silica).



Susceptibility to damage is evaluated using X-ray diffraction, a scanning electron microscope, and thin-section point counting.



Clay Swelling Clay swelling is caused by the introduction of incompatible fluid or relatively fresh water (water of lower salinity or ionicity than the original pore solution) into the pores. The expansion of the crystal unit (interlayer distance) is caused by the replacement of ions which neutralize the charge deficit by dilution and osmotic effect. Therefore, water or large dissolved ions, that are incorporated in the structure, increase the distance between layers to compensate for the electrostatic repulsion due to the net negative charge of each layer. The expansion of each crystal unit results in a macroscopic swelling of the clay particle. The swelling can seal the pore throats, resulting in permeability reduction.



Clay Migration Negatively charged particles result when the charge balance between positive (aluminum) and negative (oxygen) is disrupted through displacement of cations or breaking of the particles. Cations from solution surround the clay particle, creating a positively charged cloud. Such particles repel each other and are prone to migration. Once clay particles are dispersed, they can block pore spaces in the rock and reduce permeability. 3.3.1 Clay Types Kaolinite, illite, chlorite, smectite, and mixed-layer clays are the most common clay types. Kaolinite, Illite and chlorite are migratory clays. Smectite is a swelling clay. Mixed-layer clays can swell or migrate (or both).



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Clays exhibit a cation exchange capacity. The ionic atmosphere and stability of the clay are a function of the clay type, the cations of the surface of the clay, and the surrounding fluid. Clays in the sodium state disperse/migrate when exposed to fresh water. This occurs because of the rapid diffusion of the sodium ions into the water, creating a strong repulsion between clay particles.



Kaolinite Kaolinite is a migratory clay that is found in most sandstones. It is a 1:1 clay consisting of one tetrahedral (silica) sheet and one octahedral (alumina) sheet. The different layers are bound together because of the proximity of the hydroxyl ions of the tetrahedral sheet and the oxygen ions of the octahedral sheet. The hydrogen of the hydroxyl groups is bound at the same time with oxygens of the octahedral and tetrahedral sheets. The bond is very rigid. There is no substitution by other ions of either the aluminum in the octahedral sheet or of the silicon in the tetrahedral sheet. Therefore, there are no charge deficits on the faces of kaolinite crystals. In many sandstones, kaolinite is characterized by its loose attachment to the host grains and the large size of the individual crystals. The crystals are usually bound together in compact aggregates and are too large to be transported by moving fluids in the pore system. If these aggregates disperse, fine crystals will be liberated and entrained in the moving fluid. This is particularly true in areas of high fluid turbulence (for example, close to the wellbore). These migrating kaolinite crystals can go to a pore throat where they will lodge and act as a check valve. Thus, the migration of kaolinite depends on the state of dispersion or aggregation (flocculation) of the individual crystals.



Illite Illite is a 2:1 migratory clay consisting of two tetrahedral (silica) sheets and one octahedral (alumina) sheet. The octahedral sheet is between the tetrahedral sheets. The oxygens at the tip of the tetrahedra point toward the center octahedral sheet and substitute for two-thirds of the octahedrally coordinated hydroxyls. The most common illite mineral has approximately one-half of the silicon substituted by aluminum in the tetrahedral sheet. Substitutions in the octahedral sheet are low; approximately three-fourths of the octahedral ions is aluminum, a minor amount of ferric iron is present, and approximately one-eighth if the cations is divalent (magnesium and ferrous iron). This gives a total negative charge of approximately 0.75 which is due to substitution in the tetrahedral sheet. Because these substitutions are balanced by interlayer cations (potassium) close to this sheet, there is a strong bond between them and, therefore, there is a strong bond between the different layers. Because of this, the potassium ion in illite cannot be easily removed and replaced by ions or water molecules (or both). For this reason, illite is considered nonswelling.



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Chlorite Chlorite is a migratory clay consisting if 2:1 type layers bound by a magnesium containing octahedral sheet. The bond between layers is strongly ionic, like illite. Chlorite is a nonswelling clay. Chlorite contains iron (Fe+3 and Fe+2) substituted for aluminum, silicon, and magnesium. Chlorite is readily attacked by hydrochloric acid (HCl) and the iron liberated during dissolution can precipitate as a gelatinous ferric hydroxide when the acid spends. The ratio of ferric to ferrous iron in chlorite is typically 0.2. Therefore, iron problems, if any, can be avoided by using reducing or chelating agents (or both) in the acid. The shape of the chlorite mineral is similar to a "honeycomb" structure. This creates a microporosity which, like illite, allows water to be trapped and retained.



Smectite Smectite is a swelling clay. Normally, migratory clays are considered to have greater damage potential. Smectite can create severe plugging if it swells in the pore-throat lining. Smectite is characterized by the loosely bound cations and layers of water (or polar organic molecules) between the silica sheet. These are loosely bound because smectite has most of its charge originating in the octahedral sheet. The resulting charge deficit in the layer is balanced by an interlayer cation separated from the octahedral sheet by the tetrahedral sheet. Thus, the interlayer width is reversibly variable. The interlayer water can be driven off at temperatures greater than 250°F (121°C). Sodium, calcium, hydrogen, magnesium, iron, and aluminum are the interlayer cations commonly found. The introduction of incompatible or relatively fresh water (water of lower salinity or ionicity than the original pore solution) into the pores is the cause of smectite swelling. Smectites can be found in flocculated aggregates which can disperse, leading to the migration of the smectite particles.



Mixed-Layer A large number of clays are not pure minerals, but consist of interstratified units of different chemical compositions. These clays are called mixed-layer clays and can either migrate or swell. Illite-smectite (illite-montmorillonite) and chlorite-smectite are common mixed-layer clays with illite-montmorillonite being the most abundant. The two layers occur in all possible proportions ranging from 9:1 to 1:9. Many of those with a 9:1 or even 8:2 ratio are called illites or glauconites (all glauconites have some interlayered montmorillonite). Those having ratios of 1:9 and 2:8 are called smectite (montmorillonite). Glauconite is also used as a rock name and is applied to any aggregate of finegrained, green-layer minerals. The iron illite layers commonly occur interlayered with



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montmorillonite-like layers. In glauconites, more than one-half of the octahedral positions is predominantly filled with ferric iron. 3.3.2 Clay Control Methods Three methods of clay control are known to be effective. These are: 1.



Ionic neutralization



2.



Organic barrier



3.



Particle fusion.



3.3.2.1 Ionic Neutralization Ionic neutralization is commonly used in hydraulic fracturing and is accomplished using brines, polyvalent inorganic cations, and quaternary amine polymers.



Brines In the formation, the clays are generally not dispersed as long as their chemical environment is not changed. For this reason, brines are not nearly so damaging to sandstone as is freshwater. Aqueous solutions containing 1 to 3% (wt/wt) salt are normally used as the base liquid in fracturing fluids. KCl is used more often than NaCl or NH4Cl because K+ stabilizes clays better against invasion of water and, consequently, prevents swelling. All of these salts help maintain the chemical environment of the clay particles, but they do not provide permanent stabilization. Clay Stabilizer L237 is a temporary clay stabilizer but is more effective than KCl, NaCl, or NH4Cl. L237 will prevent formation damage caused by dispersion or swelling of clays induced by any following fresh water. Therefore, L237 concentrations can be reduced in the proppant-laden fluid stages.



Inorganic Polynuclear Cations The attraction between a negatively charged clay particle and its exchangeable cations is exponentially related to the charge on the cations. Thus, a polynuclear ion with a net charge of +8, +12, or more may be several million times more attracted to a clay particle than monovalent or divalent cations. Consequently, from electrostatic considerations alone, polynuclear ions should almost immediately displace all of the exchangeable cations and be very tightly held to the clay surface. Clay Stabilizer L42 is the inorganic polynuclear cation used by Dowell. Zirconium oxychloride is hydrolyzable metal ion forming a polynuclear cation with a high cationic charge. L42 is a permanent clay stabilizer used primarily in acidizing applications. L42 will crosslink most fracturing fluids and, typically, is not used in fracturing operations.



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Amine Polymers A monomolecular film of quaternary amine polymer is strongly adsorbed on the surface of the clays by cation exchange. More permanent stabilization is claimed since the clay particles are bridged together by multiple cationic sites along the polymer chain. To destabilize the clays, simultaneous release of all cationic sites is required for exchange with other ions in the formation brine. Quaternary amine polymers are water soluble and leave the formation water-wet. Quaternary amine polymers may be used in water-base fracturing fluids under acidic, neutral, and basic conditions. Clay Stabilizer L55 is the quaternary amine polymer used by Dowell and is normally used in reservoirs with clay content greater than 10%. 3.3.2.2 Organic Barrier Some cationic surfactants prevent deflocculation of clays by their adsorption on the clay surface (cation exchange). These cationic surfactants make clay and sandstone surfaces oil-wet. The oil-wet condition prevents the adsorption of water which would otherwise deflocculate the clays. For adequate stabilization, greater concentrations of cationic surfactants may be required as anticipated by cation exchange due to physical adsorption of a second layer of surfactant, where the new surfactant molecule is held to the former one by hydrocarbon bonding through their hydrophobic tail. This method temporarily reverses the wettability of the rock, resulting in a decrease in the permeability of the oil due to water entrapment. In most cases, reversing the wettability of the rock is undesirable. The organic barrier method is not used by Dowell. 3.3.2.3 Particle Fusion This method is technically an anionic stabilization. In this method, the repulsive forces between the dispersing clay particles are destroyed by simply destroying part of the clay mineral itself, principally the octahedral sheet. This can be accomplished by the use of the various anions of fluoride, phosphate, borate, and to some extent hydroxide. When these anions attack the clay platelets, the aluminum from the octahedral layer and the components of the injected chemical compound combine to form a very thin connecting sheet over the remaining partial and the complete (unaltered) clay platelets. This connecting sheet binds all of these formerly dispersible clay particles together. The particle fusion method is not used by Dowell. 3.4 Fluid-Loss Additives Fluid-loss control is essential for an efficient and successful fracturing treatment. The loss of fracturing fluid into the formation is generally considered to be detrimental because it decreases the fluid efficiency (or decreases the fracture



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volume created by a given volume of fracturing fluid). Excessive fluid loss can cause early termination of a treatment due to a proppant screenout. Fluid loss to the formation is a filtration process which is controlled by the following parameters. • fracturing fluid composition •



flow rate and pressure



•



reservoir properties (such as permeability, porosity, pressure and fluid saturation)



•



presence of microfissures, macrofissures, or faults.



During the fracturing treatment, fluid leaks-off and enters the pore spaces of the rock. Pore-size distribution for the rock matrix varies from formation to formation. Generally, the lower permeability formations have smaller pore openings. A 0.1-md rock may have an average pore diameter of less than 1.0-µ, while a 500-md rock may have an average pore diameter of 20-µ. The range of pore size may be quite large. Controlling fluid loss to fissures that intersect the main fracture is more difficult than controlling fluid loss to the matrix because the openings to be blocked are larger. Solid materials are used which can bridge the fractures and plug them, but their effectiveness depends on the size of intersecting fissures.



Appendix E — Fluid Loss provides additional fluid-loss information. 3.5 Friction Reducers Fluids such as water and low-viscosity oil achieve turbulence when pumped through small tubulars at high rates. This creates high friction pressures. Dramatic decreases in friction pressure are observed when turbulence is suppressed by adding polymers (friction reducers) to the fluid. Friction reducers offer no advantage unless the fluid is in turbulent flow. An already viscosified water- or oil-base fracturing fluid will not benefit from the addition of friction reducers. Similarly, a viscous oil pumped at low rate through casing or large diameter tubing exhibits little opportunity for enhanced friction reduction by adding friction reducers. High turbulence must be a factor before friction reducers are effective.



Friction Reducers for Water Polymers are high-molecular-weight molecules that have an affinity for water molecules. The polymer deters turbulence by controlling migration of the individual water molecules. Low concentrations (10 to 20 lbm/1000 gal) of guar or HPG polymers and copolymers of polyacrylamide are the most efficient friction reducers for water.



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Friction Reducers for Oil The friction reducer for oil is an acrylonitrile copolymer. Friction reduction of as much as 55% may be obtained using Oil Friction Reducing Agent J257 in crude oil. Used in refined oils, friction reduction of as much as 70% may be obtained. The oil viscosity if unaffected by friction reducers. Friction in oil may also be reduced with low concentrations of an aluminum phosphate ester gelling agent and an activator. 3.6 Temperature Stabilizers Stabilizers are used to prevent degradation of water-base fracturing fluids at temperatures greater than 200°F (93°C). The temperature stability of a fracturing fluid is dependent on the following: 1.



The stability of the polymer. Guar is less stable than HPG.



2.



The fluid pH value. Guar and guar derivatives are hydrolyzed at a low pH value, especially at elevated temperature. A high-pH fluid should be used to enhance long-term fluid stability.



3.



The presence of breakers. Fracturing fluids are degraded by breakers.



Methanol K46 and High-Temperature Gel Stabilizer J353 (sodium thiosulfate) are stabilizers used by Dowell. Stabilizer J450 is also used in the YF100HTD, YF600HT, and YF600UT fluids to extend the maximum temperature limit. The reaction mechanism of methanol and sodium thiosulfate is not fully understood. It is believed they act as oxygen scavengers and prevent rapid gel degradation caused by dissolved oxygen. Since the dissolved oxygen content is not high, they probably also enhance fluid stability by reacting with free radicals generated from thermal degradation of the polymer. The principle advantage of sodium thiosulfate is its superior performance as a stabilizer. Normally, this performance results in the use of lower polymer concentrations to achieve equivalent rheological properties. A comparison of stabilizer efficiency can be made by plotting apparent viscosity versus time. Fig 1 shows the performance of a 40 lbm/1000 gal crosslinked fluid containing 50 gal K46/1000 gal and a 40 lbm/1000 gal crosslinked fluid containing 10 lbm J353/1000 gal at 250°F (121°C) and a shear rate of 170 sec-1. J353 reduces the rate of viscosity loss normally observed with fluids containing methanol. Fig. 2 shows the performance of a 50 lbm/1000 gal crosslinked fluid containing 10 lbm J353/1000 gal compared to a 60 lbm/1000 gal crosslinked fluid containing 50 gal K46/1000 gal at 275°F (135°C) and a shear rate of 170 sec-1. This comparison shows that lower polymer loads can be used when J353 is used as a stabilizer.



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Fig. 1. Apparent viscosity of 40 lbm/1000 gal crosslinked fluids with methanol and sodium thiosulfate stabilizers.



Fig. 2. Apparent viscosity of a 50 lbm/1000 gal crosslinked fluid containing sodium thiosulfate and a 60 lbm/1000 gal crosslinked fluid containing methanol. DOWELL CONFIDENTIAL



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High-Temperature Gel Stabilizer J353 J353 is more effective than K46, increasing the fracturing fluid viscosity at elevated temperature 2- to 10-fold depending on the temperature and time of exposure to temperature. The J353 concentration is normally 10 lbm/1000 gal in water-base fracturing fluids.



Methanol K46 The original use of methanol in water-base fluids was for the purpose of lowering surface tension. This was (is) desirable, especially in low-pressure reservoirs, for enhanced fracturing fluid cleanup. These laboratory studies also revealed that methanol enhanced the viscosity of fracturing fluids at high temperature. As a result of these studies, methanol was introduced as a viscosity stabilizer. K46 is normally used at a concentration of 50 gal/1000 gal in fracturing fluids. At this concentration, K46 reduces the rate of viscosity loss, but does not significantly reduce surface tension. K46 added to the fluid at a concentration of 50 gal/1000 gal will reduce the surface tension by 15% to approximately 60 dynes/cm. A surfactant added to the fracturing fluid at a concentration of 2 gal/1000 gal will reduce the surface tension by 70% to approximately 20 dynes/cm. Fracturing fluid stability rather than surface tension reduction is the principle advantage of K46. K46 is inflammable, toxic, and hazardous to handle. J353 is noninflammable and nontoxic. The use of J353 also eliminates the logistics problems when large volumes of K46 are required. A hydraulic fracturing treatment using 400,000 gal of stabilized fluid will require 20,000 gal of K46, but only 4000 lbm of J353. 3.7 Surfactants A surface-active agent (surfactant) is a material which, at low concentration, adsorbs at the interface between two immiscible substances. The immiscible substances may be two liquids, such as oil and water, or a liquid and a gas, or a liquid and a solid. The surfactant becomes involved in the interface and lowers the amount of energy required to expand the interface. Surfactants behave this way because of their unique structures. They each contain a portion that is strongly attracted to the solvent and a portion that is not attracted to the solvent. In the case of water, the attracted portion is called hydrophilic and the unattracted portion is called hydrophobic. The hydrophobic portion is generally a hydrocarbon chain that is soluble in oil but is virtually insoluble in water. The hydrophilic portion is a very polar, often charged, group that is water soluble. If the charge of the hydrophilic group is positive, the surfactant is cationic and if the charge is negative, the surfactant is anionic. The surfactant is nonionic if the hydrophilic portion is not charged. Surfactants are often represented as in Fig. 3 and orient at an interface (for example, between oil and water).



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Fig. 3. Surfactant orientation. Surfactants are used in fracturing fluids for various reasons. These are: • Surfactants promote the formation of stable bubbles in foams. •



Surfactants stabilize the water-external emulsion in polyemulsion fluids. surfactant also acts to break the emulsion by adsorbing on the rock.



•



Surfactants promote fracturing fluid cleanup by conditioning the formation and reducing interfacial/surface tension.



The



Interfacial tension is a force with a dimension of dynes/cm that is a measure of the work required to increase the surface area between two immiscible liquids by one square centimeter. Surface tension is the same as interfacial tension except it usually applies to gas-liquid interfaces. Surfactants are also used to treat various types of damage. These are: • Surfactants remove blockage by fines. Fines can be clays, silts (clay-type minerals), or drilling-fluids solids. If a surfactant is in the fracturing fluid and wets the individual fines particles, the particles can be removed from the formation more easily when the fracturing fluid is cleaned-up. •



Surfactants prevent or treat near-wellbore water blocks. Surfactants reduce the capillary pressure by lowering the surface tension of the water. Lower energy is required to move the water through the formation matrix.



Some bactericides, clay stabilizers, and nonemulsifiers are surfactants.



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Wettability The ionic charge of surfactants is important in terms of wettability. Wettability is a term used to indicate whether the rock is preferentially coated with oil and water or both. Almost all reservoirs are naturally water-wet, which favors oil movement through the rock. The contact angle is the angle between the rock surface and the fluid measured through the fluid phase. Contact angles less than 90° measured through the water phase indicate preferentially water-wet conditions. Contact angles greater than 90° measured through the water phase indicate preferentially oil-wet conditions. A 90° contact angle indicates neutral wettability; the rock surface has equal preference for water and oil. Contact angles near 90° exhibit moderate wetting preference and cover a range termed intermediate wettability. When the contact angle is greater than 90°, the rock is considered non-wetting. Cleanup is improved by lowering the capillary pressure. The capillary pressure is the difference in pressure between a continuous oil phase and a continuous water phase in a reservoir rock. The magnitude of this pressure difference depends on the interfacial tension, pore space geometry, rock wettability, and the quantity of each phase present. can be used to explain the consequence of contact angle on capillary pressure. If a contact angle of 90° could be attained, the capillary pressure could be reduced to near zero. ρ=



2σ cos θ rp



Where:



ρ = capillary pressure σ = surface tension θ = contact angle rp = pore radius. Fig. 4 illustrates the wettability of oil/water/rock.



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Fig. 4. The wettability of oil/water/rock. Surfactants can be adsorbed on the rock, altering the wettability. Surfactants can also replace previously adsorbed surfactants and give the rock the wetting characteristic of the stronger surfactant. Mixing cationic surfactants and anionic surfactants is not advisable because of the possibility of forming precipitates. Table 1 contains the properties of common Dowell surfactants.



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Table 1. Properties Of Common Dowell Surfactants Agent



Nature



Solubility in



Surface Wettability



Brine



Acid



Oil



Sandstone



Limestone



Interfacial Tension+ (dynes/cm)



Tension++ (dynes/cm)



F40



N



S



S



S



WW



WW



31.6



2.5



F52.1



A



S



S



I



WW



WW



24.0



200°F



AR



YF500HT



AR



OR



OR



NLR



AR



AR



YF600LT



AR



NLR



OR



NLR



AR



AR



YF600HT



AR



OR



OR



NLR



AR



AR



YF600UT



AR



NR



OR



NLR



AR



AR



StableFOA M



AR



OR



NR



NLR



NR



AR (Foamer)



SuperFOA M



AR



NLR



OR



NLR



OR



AR



Super Sandfrac K1



AR



NLR



OR



NLR



OR



AR



YF"GO" III



NR



NLR



NR



NLR



NR



NR



YF"GO"IV



NR



OR



NR



NLR



NR



NR



Legend: AR - Always recommended NLR - Normally recommended NR - Not recommended OR - Occasionally recommended



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Table 6. Additive Selection Guide Additive Type



Dowell Code



Compatible Fluids



Recommended Concentration



Bactericides



Dryocide M76 M275 J134L



All water-base fluids All water-base fluids All water-base fluids YF300/400LPH (125°F [52°C]) WF fluids All water-base fluids WF fluids (93°C])



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5 to 10 gal/1000 gal 5 to 8 gal/1000 gal (aqueous phase) 5 to 8 gal/1000 gal (aqueous phase) 6 gal/1000 gal 6 gal/1000 gal 20 lb/1000 gal 10 lb/1000 gal 1 to 3 gal/1000 gal 1 to 1.3 gal/1000 gal 50 gal/1000 gal 200 gal/1000 gal



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APPENDIX D - PROPPANTS 1 Introductory Summary............................................................................................................. 2 2 Physical Properties of Proppants .......................................................................................... 3 2.1 Proppant Strength................................................................................................................ 3 2.2 Grain Size and Grain-Size Distribution ................................................................................ 4 2.3 Quantities of Fines and Impurities ....................................................................................... 5 2.4 Roundness and Sphericity ................................................................................................... 6 2.5 Proppant Density ................................................................................................................. 6 3 Classes of Proppants .............................................................................................................. 6 3.1 Sand..................................................................................................................................... 6 3.2 Resin-Coated Proppants...................................................................................................... 6 3.2.1 Precured Resin-Coated Proppants............................................................................. 7 3.2.2 Curable Resin-Coated Proppants............................................................................... 7 3.2.3 Limitations Associated With Resin-Coated Proppants................................................ 7 3.2.3.1 Oxidative Breakers........................................................................................... 8 3.2.3.2 Borate-Crosslinked Fluids................................................................................ 9 3.2.3.3 Organometallic-Crosslinked Fluids .................................................................. 9 3.3 Intermediate-Strength Proppants......................................................................................... 9 3.4 High-Strength Proppants ..................................................................................................... 9 4 Conductivity ........................................................................................................................... 10 4.1 Closure Stress ................................................................................................................... 10 4.2 Embedment........................................................................................................................ 10 4.3 Fracture Width ................................................................................................................... 11 4.4 Proppant-Pack Porosity ..................................................................................................... 12 4.5 Factors Operative in the Presence of Polymeric Fracturing Fluids .................................... 13 5 Proppant Testing ................................................................................................................... 13 6 Measurement of Proppant Addition to Fracturing Fluids .................................................. 14 DOWELL CONFIDENTIAL



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7 Proppant Selection.................................................................................................................16 8 Proppant Flowback ................................................................................................................16 FIGURES Fig. 1. Strength comparisons of various types of proppants. .......................................................4 Fig. 2. The effect of feldspar contamination on conductivity.........................................................5 Fig. 3. The relationship of proppant concentration and fracture width (no embedment). ..........12 TABLES Table 1. Proppant-Pack Porosity Of Sand And Intermediate-Strength Proppant .......................12 Table 2. Density Table For Proppant Added To Fracturing Fluid ...............................................14



1 Introductory Summary Proppants are used to keep the walls of the fracture apart so that a conductive path to the wellbore is retained after pumping has stopped and the fracturing fluid has leaked-off. Placing the appropriate concentration and type of proppant in the fracture is critical to the success of a hydraulic fracturing treatment. Factors affecting the fracture conductivity (a measurement of how well a propped fracture is able to convey the produced fluids over the producing life of the well) are: • proppant type •



physical properties of the proppant



•



proppant concentration



•



proppant-pack permeability



•



effects of postclosure polymer concentration in the fracture



•



movement of formation fines in the fracture



•



long-term degradation of the proppant.



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2 Physical Properties of Proppants The physical properties of proppants that have an impact on fracture conductivity are: • proppant strength •



grain size and grain-size distribution



•



quantities of fines and impurities



•



roundness and sphericity



•



proppant density.



2.1 Proppant Strength To open and propagate a hydraulic fracture, the in-situ stresses must be overcome. After the well is put on production, the same stresses work to close the fracture and act on the proppant. If the proppant strength is inadequate, the closure stress will crush the proppant and the resulting fines will plug the proppant pack. Permeability and, therefore, conductivity of the proppant pack will be drastically reduced. Proppants are available in different types and mesh ranges to meet the conductivity requirements of the fracture design. Common practice is to use the difference between the bottomhole fracturing pressure and bottomhole producing pressure to calculate the maximum effective stress (or closure stress) on the proppant. During flowback and testing operations, the bottomhole producing pressure is usually held constant and at a low value to maximize the production rate. The potential for maximum crushing can occur during flowback and testing operations when the flowing pressure at the perforations may be low, or initially in the production of a well because the fracture gradient is at its maximum, decreasing with reservoir pressure depletion. However, if the well is initially completed and produced at a higher bottomhole pressure and with a near constant production rate, the maximum effective stress on the proppant is less. By producing a well in this manner, the stress on the proppant can increase with time, but never exceeds the bottomhole fracturing pressure. A higher strength proppant can be used as a "tail-in" segment after the fracture has been packed with a lower strength proppant as a preventive measure against induced high closure stresses and stress concentrations near the wellbore. Strength comparisons are shown in Fig. 1. The following general guidelines may be used to select proppants. • Sand — closure stresses less than 6000 psi. •



Resin-Coated Proppants — closure stresses less than 8000 psi.



•



Intermediate-Strength Proppants — closure stresses greater than 5000 psi but less than 10,000 psi.



•



High-Strength Proppants — closure stresses greater than 10,000 psi. DOWELL CONFIDENTIAL



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Proppant type and size should be determined by comparing economic benefits versus cost. This is accomplished using the FracNPV* software.



Fig. 1. Strength comparisons of various types of proppants. 2.2 Grain Size and Grain-Size Distribution



Grain Size — Proppants with larger grain sizes provide a more permeable pack; however, their use must be evaluated in relation to the formation that is propped and the increased difficulties encountered in proppant transport and placement. Dirty formations, or those subject to significant fines migration, are poor candidates for large proppants. The fines tend to invade the proppant pack, causing partial plugging and a rapid reduction in permeability. In these cases, smaller proppants, which resist the invasion of fines, are more suitable. Although they offer less initial conductivity, the average conductivity over the life of the well will be higher and will more than offset the initial high productivity provided by larger proppants (which is often followed by a rapid production decline). Larger grain sizes can be more difficult to use in deeper wells because of greater susceptibility to crushing due to higher closure stresses (as grain size increases, strength decreases) and placement problems. Placement problems are two-fold — a wide fracture is required for the larger grains, and the particle settling rate increases with increasing size. *



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Grain-Size Distribution — If the grain-size distribution is such that the mesh range contains a high percentage of the smaller grains, the proppant-pack permeability and therefore conductivity will be reduced. Minimizing the mesh range will increase the permeability. For naturally occurring sand, this will result in a large amount of waste. A manufactured proppant such as intermediate-strength proppant (ISP) can be manufactured in narrow mesh ranges. Typically, 20/40-mesh ISP is in fact nearer to 20/30 mesh. 2.3 Quantities of Fines and Impurities Grain-size distribution and the quantities of fines and impurities in the proppant are closely related. A high percentage of fines or impurities can reduce the proppantpack permeability. The effect on the proppant pack is the same as invading formation fines. Fig. 2 illustrates the effect of feldspar contamination on conductivity. Acid solubility is generally used as an indication of the amount of impurities such as carbonates, feldspar, and iron oxides present in the proppant. For proppant mesh sizes 6/20 through 30/50, the maximum allowable solubility is 2% (American Petroleum Institute RP 56).



Fig. 2. The effect of feldspar contamination on conductivity.



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2.4 Roundness and Sphericity The roundness and sphericity of a proppant grain can have a dramatic effect on fracture conductivity. Proppant grain roundness is a measure of the relative sharpness of grain corners, or of grain curvature. Particle sphericity is a measure of how close the proppant particle or grain approaches the shape of a sphere. When the grains are round and about the same size, stresses on the proppant are more evenly distributed, resulting in higher loads before grain failure occurs. 2.5 Proppant Density Proppant density has an influence on proppant transport and placement. Highdensity proppants are more difficult to suspend in the fracturing fluid and to transport in the fracture. Placement can be achieved in two ways — using high-viscosity fluids which carry the proppant for the entire length of the fracture with minimal settling, and using low-viscosity fluids at a higher flow rate. Clearly, higher-density proppants also require more mass of material to create the same fracture volume.



3 Classes of Proppants 3.1 Sand Sand is the most often used proppant. It is the most economical, is readily available, and provides sufficient fracture conductivity at closure stresses less than 6000 psi. Depending on the overall balance of physical properties, sand can be subdivided into groups. • Northern White Sand •



Texas Brown Sand



•



Colorado Silica Sand



•



Arizona Silica Sand



Based on the American Petroleum Institute (API) standards, any sand source can be qualified and grouped similar to the above sands. 3.2 Resin-Coated Proppants Resin coatings are applied to sand (usually Northern White Sand) to improve proppant strength. Resin-coated sand is stronger than conventional sand and may be used at closure stresses less than 8000 psi, depending on the type of resincoated sand. At closure stresses greater than 4000 psi, resin-coated sand has a higher conductivity than conventional sand. The resin helps spread the stress over a larger area of the sand grain and reduces the point loading. When grains crush, the resin coating helps encapsulate the crushed portions of the grains and prevents them from migrating and plugging the flow channel. In some cases, resin-coated proppants may be used as an alternative to an intermediate-strength proppants. DOWELL CONFIDENTIAL



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3.2.1 Precured Resin-Coated Proppants The resin coating on the proppant is (at least partially) cured during the manufacturing process to form a nonmelting inert film. Proppants processed in this fashion are called precured resin-coated proppants. The major application of precured resin-coated proppants is to enhance the performance of sand at high stress levels. 3.2.2 Curable Resin-Coated Proppants A curable resin coating may also be applied to sand. The major application of curable resin-coated proppants is as an attempt to prevent the flowback of proppants near the wellbore. Theoretically, the curable resin-coated proppants are mixed and pumped in the last stage of the treatment and the well is shut in for a period of time to allow the resin to bind proppant particles together and cure into a consolidated, but permeable filter. Treatment Design provides additional information concerning proppant flowback control methodology. Curable resin-coated proppants should only be used as a last resort to control proppant flowback. 3.2.3 Limitations Associated With Resin-Coated Proppants Various resin-coated proppants can affect fracturing fluid performance, and fracturing fluids can affect the performance of resin-coated proppants. The following guidelines are recommended if resin-coated proppants are required by the client. • Minimize the amount of resin-coated proppants. •



Use precured resin-coated proppants. These materials are (at least partially) cured and are typically less damaging than fully curable resin-coated proppants.



•



Avoid using resin-coated proppants in conjunction with oxidative breakers. Resin-coated proppants will decrease breaker effectiveness. Some resin-coated proppants have very little effect on breaker activity. Additional breaker must be used when other resin-coated proppants are used.



•



Always determine fracturing fluid/resin-coated proppant compatibility before pumping. Typically, 30 to 60% of the resin coating is lost to the fluid. Resin loss does not behave in a straight-forward manner with changes in temperature or time at temperature. Resin loss increases as exposure to shear increases.



•



Never batch-mix resin-coated proppants in fracturing fluids.



•



Minimize handling of the resin-coated proppants to keep dust levels low. Solid resin is a good emulsion stabilizer and can create an emulsion with the fracturing fluid that is not miscible in water.



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3.2.3.1 Oxidative Breakers Breaker J218, EB-Clean ∗ J475 Breaker, EB-Clean LT J479 Encapsulated Breaker, and Breaker J481 react with the resin coating on curable and precured resin-coated proppants. The reaction results are: • additional resin loss •



compressive strength reduction



•



conductivity reduction



•



consumption of breaker by the resin.



The particulate form of the encapsulated breakers (J475 and J479) and the resultant localized release create a locally very high concentration of breaker. This effect has not been extensively studied; however, numerous conductivity tests have been performed using various fluid/breaker/resin-coated proppant combinations. Observation of proppant-packs following fracture conductivity testing has shown that the effect is limited to the faces of the proppant grains immediately near the site where active breaker is being released from the breaker particle. Approximately 4 to 8 of the nearby proppant grains are affected, with roughly the closest 1/3 to 1/4 diameter (20/40 mesh) of resin coating removed from these proppant grains. Typically, more than half of the removed resin is dissolved with the remainder remaining as flakes. Since this is a surface reaction, the curable resin-coated proppants are more reactive than are the precured resin-coated proppants. J218 also reacts with resin-coated proppants; however, since the J218 is dissolved, the effects on the resin-coated proppants are not localized. Some of the J218 is consumed by the resin-coated proppants. Loss in curable resin-coated proppant compressive strength should be expected. Typically, much lower (active) concentrations of J218 (for example, 0.5 lbm/1000 gal versus 5 lbm/1000 gal) are used so the effects are further limited. Some resin-coated proppants have very little affect on J481. Other resin-coated proppants reduce J481 performance considerably and additional J481 must be used. Two important points are:



∗



1.



The effects of resin-coating degradation (flakes and loss of strength) on proppant-pack conductivity are negligible in virtually all field conditions. The effects of the concentrated polymer causing a reduction in conductivity are presumed to be greater than the effects of resin-coating degradation.



2.



The major problem that must be overcome is the consumption of breaker (encapsulated or dissolved) by the (reaction with) resin-coated proppants. Adding additional breaker will improve conductivity, but will also degrade more of the resin coating. At some point, diminishing returns should be expected.



Mark of Schlumberger



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3.2.3.2 Borate-Crosslinked Fluids The addition of resin-coated proppants results in a decrease in the fluid pH value. This can result in fluid decomposition. The amount of pH value decrease is dependent on the brand and amount of resin-coated proppants. The resin-coated proppant/fracturing fluid compatibility should be tested prior to pumping. Different proppants (and even different lots of proppant from a supplier) and proppant concentration can affect the final pH value and fluid stability. Additional resin-coated proppant information is provided in the appropriate manual sections in the Fracturing Materials Manual — Fluids. 3.2.3.3 Organometallic-Crosslinked Fluids The addition of resin-coated proppants, especially curable resin-coated proppants, to organometallic-crosslinked fracturing fluids can interfere with the crosslinking mechanism. The major factor affecting fracturing fluid performance is the reduction in the active metal crosslinker. The metal is complexed by the resin surface and is not available for crosslinking the polymer. Reduction in the crosslinker varies from 15 to 40%. The resin coating also lowers the pH value. The resin-coated proppant/fracturing fluid compatibility should be tested prior to pumping. Different proppants (and even different lots of proppant from a supplier) and proppant concentration can affect the final pH value and fluid stability. Additional resin-coated proppant information is provided in the appropriate manual sections in the Fracturing Materials Manual — Fluids. 3.3 Intermediate-Strength Proppants ISP is fused ceramic (low-density) proppant or sintered bauxite (medium-density) proppant. The sintered bauxite ISP is processed from bauxite ore containing large amounts of mullite. This is in contrast to a high-strength proppant which is processed from bauxite ore high in corundum. ISP is used at closure stresses greater than 5000 psi, but less than 10,000 psi. 3.4 High-Strength Proppants High-strength proppants are sintered bauxite containing large amounts of corundum, and is used at closure stresses greater than 10,000 psi. High-strength proppant is the most costly proppant.



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4 Conductivity Fracture conductivity is a measurement of how well the propped fracture is able to convey the produced fluid or fluids. The physical properties of proppants will affect fracture conductivity. Other factors that have an impact on fracture conductivity are: • closure stress •



embedment



•



fracture width



•



proppant-pack porosity



•



factors operative in the presence of polymeric fracturing fluids.



4.1 Closure Stress Apart from linear variations in stresses with depth due to the gradients, in-situ stresses also depend on the lithology of the formation, tectonic components, and pore pressure. For calculations regarding proppants, closure stress may be represented by Eq. 1. CS = (PfgD) – BHPP



(1)



Where: CS = closure stress (psi) Pfg = fracture gradient (psi/ft) D = depth (ft) BHPP = bottomhole producing pressure (psi). 4.2 Embedment Embedment is a process by which the fracture closes onto the proppant pack, reducing fracture width and conductivity. It occurs when the effective closure stress increases as a result of the reservoir pressure depletion. When fracturing formations where embedment can occur, a wider fracture and a higher concentration of proppant (weight per unit of fracture area) are required to counteract the reduction in conductivity due to embedment. The depth of embedment will be limited to one-half of a proppant grain diameter on each fracture face in most formations. However, in very soft formations such as chalk, the depth of embedment may be more severe.



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4.3 Fracture Width The propped fracture width (no embedment) is related to the proppant concentration by Eq. 2. w=



C p 12



(1 − φ p )ρ



(2)



Where: w = propped width (in.) Cp = proppant concentration (lbm/ft2) φp = proppant-pack porosity (%)



ρ = proppant absolute density (lbm/ft3). Although the maximum conductivity can theoretically be obtained from a partially monolayer system, actual placement of a partial monolayer is virtually impossible to achieve. Proppant embedment can cause total loss of conductivity in a monolayer system. Therefore, the propped fracture is usually designed to have multiple layers of proppant. By increasing the proppant concentration, multiple layers of proppant will result and the fracture conductivity will increase because of the increased fracture width associated with multiple layers. Multiple-layer proppant packing requires a fracturing fluid with enough viscosity to create a fracture width that is sufficient for entrance of the proppant at a higher concentration. Fig. 3 illustrates the relationship of proppant concentration and fracture width for 20/40-mesh sand. Once a multilayer packing is achieved, the fracture width increases proportionately to the increase in proppant concentration. Consequently, the fracture conductivity also increases. The fracture width must be sufficient to inject the proppant at a higher concentration, and the selected proppant must have sufficient permeability under closure stress conditions to maintain the optimum conductivity.



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Dowell



Fig. 3. The relationship of proppant concentration and fracture width (no embedment). 4.4 Proppant-Pack Porosity The fracture width is reduced as the closure stress increases. This reduces the pore volume to proppant volume ratio within the fracture, and therefore reduces the proppant-pack porosity. Table 1 provides the proppant-pack porosity of sand and intermediate-strength proppants for various closure stresses.



Table 1. Proppant-Pack Porosity Of Sand And Intermediate-Strength Proppant Porosity (%)



Closure Stress, Sand (psi)



Closure Stress, ISP (psi)



37.0



1000



4000



33.5



3000



6000



30.0



5000



8000



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4.5 Factors Operative in the Presence of Polymeric Fracturing Fluids Proppant-pack permeability is significantly impaired by the concentration of polymer in water-base fracturing fluids. The severity of damage is strongly dependent on the type of fluid used and the surface polymer concentration. Final postclosure polymer concentrations can be 10 to 15 times greater than the original polymer concentration. Additional information on proppant-pack damage is provided in .



5 Proppant Testing The API has established recommended practices for testing proppants. proppant evaluation includes the following: • proppant sampling and splitting •



determination of bulk density, apparent density, and absolute density



•



sieve analysis



•



determination of roundness and sphericity



•



determination of acid solubility



•



silt test (turbidity method)



•



determination of crush resistance.



The



The following are the testing references. API RP 56, Recommended Practices for Testing Sand Used in Hydraulic Fracturing Operations , First Edition, American Petroleum Institute (1983). API RP 60,Recommended Practices for Testing High-Strength Proppants Used in Hydraulic Fracturing Operations, First Edition, American Petroleum Institute (1989). These testing references also contain the minimum and maximum allowables for the different proppant properties. The allowables are generally considered as minimum. For example, the roundness and sphericity of 0.6 is often exceeded and may be 0.9 for "high quality" sand. API RP 56 and API RP 60 are available from the American Petroleum Institute, Publications and Distribution Section, 1220 L Street, NW, Washington, DC 20005, Telephone: 202.682.8375.



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6 Measurement of Proppant Addition to Fracturing Fluids Hydraulic fracturing fluids containing proppants are slurries. Slurries are composed of a fluid and a solid. The slurry density, or mass per unit volume of fluid, is expressed as lbm/gal or g/cm3 or kg/m3. Slurry density is a critical parameter used in hydraulic fracturing operations to control the amount of proppant added to the fracturing fluid. Occasionally, two terms are used interchangeably, but have very different meanings. These are PPA, which is Pounds of Proppant Added to a gallon of liquid, and lbm/gal, which is slurry weight in Pounds Per Gallon. Fracturing treatments are designed using stages of slurry volumes containing ever increasing proppant concentrations in the slurry. As more proppant is added to the slurry, the quantity of liquid required decreases due to the additional volume taken up by the proppant (illustrated in Table 2).



Table 2. Density Table For Proppant Added To Fracturing Fluid Specific Gravity of Fracturing Fluid = 1.00 Weight Density of Fracturing Fluid = 8.345 lbm/gal Proppant is Sand (SG = 2.65, Density = 22.1 lbm/gal) Pounds Proppant Added to One Gallon 0.00



Pounds Proppant in one Gallon Slurry 0.00



Weight Density of Slurry (lbm/gal)



Gallons Liquid SG of Slurry



in One Gallon Slurry



Slurry Yield



8.35



1.00



1.00



1.00



1.00



0.96



8.94



1.07



0.96



1.05



2.00



1.83



9.49



1.14



0.92



1.09



3.00



2.64



9.99



1.20



0.88



1.14



4.00



3.39



10.45



1.25



0.85



1.18



5.00



4.08



10.88



1.30



0.82



1.23



6.00



4.72



11.28



1.35



0.79



1.27



7.00



5.32



11.66



1.40



0.76



1.32



8.00



5.87



12.00



1.44



0.73



1.36



9.00



6.40



12.33



1.48



0.71



1.41



10.00



6.89



12.63



1.51



0.69



1.45



The properties of a fracturing fluid are controlled with the use of additives. The additive quantities in a fracturing fluid are always calculated based on a "clean" fluid (fluid without proppant), and not on the slurry. As Table 2 illustrates, large errors in



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the calculation of additive quantities would take place if calculations were based on the slurry volume rather than the liquid phase. The slurry density in fracturing treatments is measured by a densitometer. The densitometer will read either pounds of proppant added to one gallon of liquid (PPA), weight density of fluid (lbm/gal), or both. Occasionally, the slurry density weight, specific gravity of the slurry or liquid, or proppant volume in the slurry must be calculated. The following equations may be used for these purposes.



Pounds of Proppant in One Gallon of Slurry (Eq. 3) χ



χ 1+ 8.345SG p



(3)



Weight Density of Slurry (lbm/gal) (Eq. 4) χ + 8.345 SGL χ 1+ 8.345 SG p



(4)



Specific Gravity of Slurry (Eq. 5) χ + 8.345 SGL χ 8.345 + SG p



(5)



Gallons of Liquid in One Gallon of Slurry (Eq. 6) 1−



χ 8.345SG p + χ



(6)



1+



χ 8.345 SG p



(7)



Slurry Yield (Eq. 7)



Where: SGL = specific gravity of the liquid phase SGp = specific gravity of the proppant x = pounds of proppant added to a gallon of liquid (lbm).



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7 Proppant Selection The selection of a proppant involves many compromises imposed by economical and practical considerations. Criteria for selecting proppant type, size, and concentration is based on a match of the fracture flow capacity to the formation permeability to provide the highest production rates consistent with economics. Treatment Design provides proppant selection and scheduling information.



8 Proppant Flowback Treatment Design provides information concerning proppant flowback.



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Appendix E - Fluid Loss



Section 1500 May 1998 Page 1 of 19



Appendix E - Fluid Loss 1 Introductory Summary............................................................................................................. 2 2 Filtrate-Dependent Leakoff ..................................................................................................... 3 2.1 Wall-Building Coefficient ...................................................................................................... 5 2.2 Viscosity Control Coefficient ................................................................................................ 7 2.3 Compressibility Coefficient................................................................................................... 7 2.4 Fracturing Fluid Coefficient .................................................................................................. 8 2.5 Total Leakoff Volume ........................................................................................................... 8 2.6 Fluid-Loss Mechanisms and Permeability............................................................................ 8 3 Pressure-Dependent Leakoff .................................................................................................. 9 3.1 Geologic Discontinuities....................................................................................................... 9 3.2 Opening Natural Fissures .................................................................................................... 9 3.3 Fluid-Loss Control in Fissures ........................................................................................... 10 4 Types of Fluid-Loss Additives.............................................................................................. 11 4.1 Inert Particulates ................................................................................................................ 11 4.2 Soluble Particulates ........................................................................................................... 11 4.3 Oil-in-Water Emulsions ...................................................................................................... 12 5 Formation Considerations .................................................................................................... 12 5.1 Fluid Loss to the Rock Matrix............................................................................................. 12 5.1.1 Pore-Size Determination........................................................................................... 13 5.1.1.1 Experimentally ............................................................................................... 13 5.1.1.2 Calculation ..................................................................................................... 13 5.2 Fluid Loss to Fissures ........................................................................................................ 13 6 In-Situ Measurement of Fluid-Loss Coefficients ................................................................ 16 7 Guide to Dowell Fluid-Loss Additives ................................................................................. 17 7.1 Fluid-Loss Additive Sizing .................................................................................................. 18 DOWELL CONFIDENTIAL



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FIGURES Fig. 1. Fig. 2. Fig. 3. Fig. 4. Fig. 5. Fig. 6. Fig. 7. Fig. 8.



Zones of invasion. .............................................................................................................3 The relationship of the fluid-loss coefficient to fluid volume and fracture length. .............4 Typical fluid-loss data for a wall-building fluid. ..................................................................6 Log-log plot of fracture pressure indicating possible fluid loss to fissures......................10 Opening of fissures..........................................................................................................10 Idealized G Plot (from the DataFRAC software)..............................................................16 Bridging particle size versus pore-throat diameter. .........................................................18 Bridging particle size versus approximate permeability...................................................19 TABLES



Table 1. Influence Of Natural Fissures In Low-Permeability Rock .............................................15 Table 2. Guide To Dowell Fluid-Loss Additives ..........................................................................17



1 Introductory Summary Fluid loss can be described as leakage of the fracturing fluid out of the main fracture. The rate of fluid leakoff (fluid loss) to the formation is one of the most critical factors involved in determining fracture geometry and treatment design. Only the fluid that remains in the main fracture is useful in propagating the fracture. Fluid that leaks-off is wasted. The volume of fluid loss during a hydraulic fracturing treatment determines the fracturing fluid efficiency (ratio of fracture volume to volume pumped). Excessive fluid loss can cause early termination of a treatment due to a proppant "screenout." The rate of fluid loss also influences fracture closure time and may influence proppant distribution in the fracture. Fluid loss to the formation is a filtration process which is controlled by the following parameters. • fracturing fluid composition •



flow rate and pressure



•



reservoir properties (permeability, porosity, pressure and fluid saturation)



•



presence of microfissures, macrofissures, or faults.



The efficiency of a fracturing fluid can be greatly improved by adding materials to control fluid loss.



Reactive Fluids A discussion of fluid loss associated with reactive fluids is provided in Acid Fracturing.



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Appendix E - Fluid Loss



Section 1500 May 1998 Page 3 of 19



2 Filtrate-Dependent Leakoff Prior to the fracturing treatment, the formation contains a number of fluids (for example, hydrocarbons, water) with different flow properties. When the fracturing fluid penetrates a formation, there may be three zones (Fig. 1): • a filter cake with varying thickness (R1) •



a zone invaded by the filtrate (R2)



•



a region with the reservoir fluids only (R3).



Fig. 1. Zones of invasion. For the purposes of treatment design, the comparative effectiveness of different fracturing fluids is expressed in terms of a fluid-loss coefficient (units of ft/min½). The fluid-loss coefficient is a measure of the flow resistance of the fracturing fluid leaking off into the formation during pumping operations. The relationship between the fracturing fluid characteristics and the formation characteristics is determined by the fluid-loss coefficient.



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During a fracturing treatment, only the volume of fracturing fluid that remains within the walls of the fracture is effective. The fluid that leaks-off into the formation matrix is lost, insofar as additional fracture extension is concerned. Fig. 2 illustrates the relationship of the fluid-loss coefficient to fluid volume and fracture length.



Fig. 2. The relationship of the fluid-loss coefficient to fluid volume and fracture length. The fracturing fluid effectiveness is dependent upon the various linear flow mechanisms controlling the amount of fluid loss taking place during the fracturing treatment. There are three types of linear flow mechanisms (fluid-loss coefficients). These are • the wall-building coefficient (Cw) •



the viscosity control coefficient (Cv)



•



the compressibility coefficient (Cc).



The Cw is determined experimentally. The Cv and Cc can be calculated from reservoir data and fracturing-fluid viscosity. All three mechanisms act simultaneously during a fracturing treatment and affect the efficiency of the fluid. The rate of fracturing fluid loss into the formation is governed by the Fluid-Loss Coefficient (C), a combination of all three mechanisms. Example calculations of the leakoff coefficients and leakoff comparisons are provided in A Practical Companion to Reservoir Stimulation. DOWELL CONFIDENTIAL



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Appendix E - Fluid Loss



Section 1500 May 1998 Page 5 of 19



2.1 Wall-Building Coefficient Refer to Fig. 1. In the first region (R1), polymer and fluid-loss additive particles are deposited and form a filter cake. The permeability of the cake is very low. The rate of fluid flow through the cake is governed by Cw. The spurt value (Sp) represents the volume of fluid that leaks off during formation of the filter cake. The spurt loss reduces the volume of fluid available for fracture extension. For wall-building fluids, the filter cake continues to grow with time and the fluid-loss rate decreases. For ideal wall-building fluids, a plot of filtrate volume versus the square root of time produces a straight line. The slope of this line is used to calculate the Cw and the y intercept is used to calculate the Sp. The Cw is directly proportional to the leakoff velocity through the established filter cake. By using the y intercept to calculate spurt, the assumption is made that the filter cake is instantaneously established. Since a finite time is required for an effective cake to be formed, calculated spurt only approximates the fluid volume lost during filter-cake formation. Eq. 1 is the mathematical expression for Cw and Eq. 2 is the mathematical expression for Sp. Cw =



0.0164m , ft / min 1/ 2 A



(1)



Sp =



24.4b , gal / 100 ft 2 A



(2)



Where: m = slope (mL/min½) A = area of the core (cm2)



Where: b = y intercept (mL) A = area of the core (cm2) Fig. 3 illustrates data from a typical fluid-loss test using a wall-building fluid. Cw values vary from as low as 0.0001 ft/min½ to a maximum of 0.03 ft/min½. The lower values indicate a more efficient fluid. Fracturing fluids containing guar or hydroxypropylguar (HPG) polymers with appropriate fluid-loss additives are good wall-building fluids.



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Fig. 3. Typical fluid-loss data for a wall-building fluid. THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY.



Testing Under Static and Dynamic Flow Conditions Although most fluid-loss data are generated in static conditions, these rates may be misleading because the filter cake is allowed to grow without being subjected to erosion. Also, the effects of shear on fluid-loss rates cannot be determined in static tests. Filter-cake erosion and fluid degradation under conditions of shear and temperature have been the subject of considerable study. The results from these studies have shown that dynamic filtration velocities of fracturing fluids tend to increase as the shear rate and temperature increase. Dynamic flow fluid-loss tests that were performed at 40 sec-1 (which approximates fracture conditions in many instances) produced data similar to static test results. Comparable results were found for uncrosslinked fluid and for borate- and organometallic-crosslinked fluids. Also, shear rates greater than 80 sec-1 in dynamic tests caused organometallic-crosslinked fluid to have higher leakoff rates than uncrosslinked- or borate-crosslinked fluid. Differences in fluid-loss behavior among the fluids seemed directly related to differences in filter cake. The organometallic-crosslinked fluid produced a thin, consolidated filter cake about one-half as thick as the soft filter cake formed by the uncrosslinked and borate-crosslinked fluids.



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2.2 Viscosity Control Coefficient The second region (R2 in Fig. 1) contains the filtrate. Viscosity of the filtrate and relative permeability to the filtrate tend to control fluid loss when the viscosity of the fracturing fluid is greater than that of the reservoir fluid. The Cv is most likely to be in effect when a gas reservoir is fractured with a nonwall-building, high-viscosity fluid. Polyemulsions, water-base fluids containing hydroxyethylcellulose (HEC) polymers, and viscous oils are fluids that have a high-viscosity filtrate. (The viscosity of the filtrate from a wall-building fluid is much lower than the viscosity of the fracturing fluid itself if the polymer filters out on the formation face.) The filtrate flow rate is governed by Darcy's law. Derived from Darcy's law is the mathematical expression (Eq. 3) for Cv. Cν = 1.48 E



− 3  k f ∆pφ 



  µf



1/ 2



 



(



, ft / min 1/ 2



)



(3)



Where: kf = relative formation permeability to the filtrate (md) ∆p = differential pressure between the fracture and the formation pore pressure (psi)



φ = formation porosity (decimal fraction) µf = viscosity of the filtrate at bottomhole conditions (cp). 2.3 Compressibility Coefficient The third region (R3 in ) has the flow of the native fluids alone. The compressibility, viscosity, and relative permeability to those reservoir fluids affect the rate of leakoff of the fracturing fluid. This control mechanism is most effective when the reservoir and fracturing fluids have very similar physical properties and are not very compressible. Leakoff is slowed because the noncompressible fracturing fluid must compress and displace the noncompressible reservoir fluid in order to penetrate the formation matrix. The mathematical expression (Eq. 4) for Cc is Cc = 119 . E



−3



 k c φ ∆p r t   µr 



1/ 2



(



, ft / min 1/ 2



)



(4)



Where: ∆p = differential pressure between the fracture and the formation pore pressure (psi), kr = formation permeability to formation fluid (md), ct = total formation compressibility (psi-1), φ = formation porosity (decimal fraction), and



µr = viscosity of the formation fluid at reservoir conditions (cp).



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2.4 Fracturing Fluid Coefficient The rate of fracturing fluid loss into the formation is governed by C which is a combination of the coefficients Cw, Cv, and Cc. Several methods have been proposed for combining Cw, Cv, and Cc. The simplest method of doing this is to conclude that the rate of fluid loss is primarily regulated by either the effectiveness of the filter cake (it is less permeable than the rock) or by the formation and fluid characteristics. For this purpose, Cv and Cc are combined to form the viscosity, compressibility coefficient (Cvc) and it is then compared to Cw. The smaller of the two is used in fracture design calculations. This is analogous to flow being limited by the smaller of two chokes in series. The mathematical expression (Eq. 5) for Cvc is: Cνc =



Cν +



(



2Cν Cc Cν2



+



4Cc2



)



1/ 2



, ft / min 1/ 2



(5)



2.5 Total Leakoff Volume An estimate of the total leakoff volume (V) per unit area at any time can be calculated using Eq. 6. This equation assumes an average of the formation permeability. A more accurate value may be obtained by calculating Cv , Cc, and Sp for individual sections of the formation height exhibiting a range of permeabilities.



( )



(



V = S p + 2( Cνc or Cw ) t 1/ 2 (7. 48), gal / ft 2



)



(6)



Where: Sp = spurt loss (gal/ft2) Cvc = viscosity, compressibility coefficient (ft/min½) Cw = wall-building coefficient (ft/min½) t = time (min). 2.6 Fluid-Loss Mechanisms and Permeability The fluid-loss-control mechanisms apply for all permeabilities. For instance, in lowpermeability, hydraulically fractured formations, the three regions of filter-cake, filtrate-invaded, and reservoir-fluid zones provide the pressure differentials to control leakoff. The depth of polymer invasion is limited to near the fracture surface and the dominant filter cake quickly forms. In high-permeability formations, a fourth region exists where polymer and particulates invade, providing reduced formation permeability and additional pressure loss. This is referred to as deep-bed filtration. Additional fluid-loss information for high-permeability formations is provided in HyPerSTIM Service.



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3 Pressure-Dependent Leakoff Pressure-dependent leakoff due to fluid loss into fissures leads to non-ideal treating pressure behavior and is thought to contribute to screenout in low-permeability formations where limited fluid loss would otherwise be anticipated. 3.1 Geologic Discontinuities Fissures and other forms of discontinuities are a widespread characteristic of rock masses. Dimensionally, discontinuities extend from the scale of crystal features (for example, transform faults) to the scale of petrographic features (for example, microcracks). Evidence also suggests that these features exist from near the surface to great depths. The extent to which the behavior of a discontinuous rock mass differs from that of a rock mass consisting of only the host rock matrix is a function of the discrepancy between the properties of the discontinuities and those of the matrix. For example, in a crystalline lithology, a few small aperture fractures may result in a large-scale permeability which is many orders of magnitude greater than that of the matrix. The same fractures in a more permeable clastic lithology may be of little consequence. The extent to which discontinuities contribute to rock-mass behavior is also governed by the scale of the features relative to a scale of interest (for example, the height or length of a hydraulic fracture). 3.2 Opening Natural Fissures Fig. 4 illustrates a log-log plot of net pressure versus time. Small positive slope (phase 1) indicates the fracture is propagating under contained height and free lateral extension. Zero slope (phase 2) indicates constant pressure. One interpretation for constant pressure is increased fracture height; however, increased fracture height is usually indicated by negative slope. Another interpretation is the opening and inflating of fissures that are crossed by the hydraulically induced fracture. These fissures normally have relatively higher permeability than the matrix and the fluid can readily penetrate into the fissures and maintain a pressure nearly equal to the pressure in the primary fracture. The fissures will open when the fluid pressure exceeds the formation stress acting across them. When this magnitude of pressure is reached, the fissures open and act to regulate the pressure at this critical magnitude (phase 2). A significant portion of the fracturing fluid can be lost in this process because of a large number of fissures that can open at this critical pressure. Unit positive slope (phase 3) indicates flow restriction. The flow restriction can be caused by accelerated fluid loss, leading to excessive slurry dehydration and a screenout.



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Fig. 4. Log-log plot of fracture pressure indicating possible fluid loss to fissures. Fig. 5 also illustrates the different phases. In phase 1, the fracture extension pressure (pe) is less than the minimum stress of the fissure (σf) and the fracture continues to propagate. In phase 2, pe is approximately equal to σf. The net pressure required for the fissures to open and inflate = σf - σH,min /1-2v ≅ 1.5 ∆σ where v is Poisson's ratio for the rock and ∆σ is the difference in principal horizontal stresses. This implies that effective fracturing not only requires a significant stress difference for vertical barriers, but also a significant stress difference between the principal stresses in the horizontal plane to avoid opening fissures. In phase 3, the flow is being restricted.



Fig. 5. Opening of fissures. 3.3 Fluid-Loss Control in Fissures Fluid-loss additives can be used to control fluid loss to fissures. A 300-mesh material in the pad fluid will bridge fissures before they open, but will not bridge open fissures or the fracture tip. A 100-mesh material between the pad fluid and slurry will bridge open fissures. Tip screenouts can also be avoided by using 100-mesh material between the pad fluid and slurry. DOWELL CONFIDENTIAL



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High-quality foam fluids can retard fluid loss in fissures because of high yield stress in the fluid. Yield stress in foam fluids is discussed in Foam Fracturing. The use of a foam fluid may alter the pressure response of opening fissures and provide a more gradual transition between phase 1 and phase 2 (Fig. 4 and Fig. 5).



4 Types of Fluid-Loss Additives A wide range of liquid and solid fluid-loss additives is available. Additives are divided into several types. 4.1 Inert Particulates Inert fluid-loss additives are the least costly and most widely used additives, but may cause some reduction in formation and proppant-pack permeability and conductivity. Although permeability damage in the formation near the fracture walls is not desired, studies indicate that it has little effect on well productivity. Proppant-pack damage can have a significant effect on well productivity. Silica flour (Fluid Loss Agent J84 and Fluid-Loss Additive J418) is milled silicon dioxide. Due to its wide range of particle sizes, it is effective in reducing fluid loss to the rock matrix and fissures. A 10-fold reduction in spurt loss for 5- to 100-md rock has been reported when silica flour is used. The effectiveness of inert fluid-loss additives is enhanced if the fracturing fluid contains a material to agglutinate (combine) with the fluid-loss additive. An agglutinative agent acts as a sealer around the inert fluid-loss additive. Guar or HPG polymers will act as agglutinative agents in water-base fluids. Soluble polymers such as cellulose derivatives or xanthan will not develop a filter cake and, therefore, are not agglutinative agents. Most crude oils contain enough paraffin or asphaltenes to act as agglutinative agents. Adomite Aqua+ (Fluid-Loss Additive J110) is a mixture of enzyme- and temperaturedegradable components and is effective at reducing fluid loss to the rock matrix only. J110 is the most costly of the inert fluid-loss additives. Other inert wall-building agents include FLA* J478 Slurriable/Degradable Additive, which is composed of starches and Adomite Mark II (Fluid-Loss Additive J126) which is intended for use in oil-base fracturing fluids other than YF* "GO" fluids. 4.2 Soluble Particulates Oil-soluble resins (Fluid-Loss Additive J168 and Fluid-Loss Additive J426) are effective fluid-loss additives. These materials, when they are sized properly and have a high enough softening point, can bridge the pore spaces and fissures and cause plugging and reduce fluid loss. An advantage that these materials have over inert particulates is that they are oil soluble and are dissolved in the produced hydrocarbon. Because they dissolve, there is no formation or proppant-pack + *



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damage associated with these materials. A wide range of particle sizes is available. These additives are more costly than the inert particulates. Fluid Loss Agent J238 is an oil-soluble resin that can be used to control leakoff in aqueous base fracturing fluids. Its primary use is as a fluid-loss additive in matrix treatments. 4.3 Oil-in-Water Emulsions An effective and popular method for controlling fluid loss is to use emulsified fluids. Petroleum-base additives (Diesel Oil U51 and Fluid-Loss Additive J451) are used to create oil-in-water emulsions with water-base fracturing fluids. The two-phase fluids reduce the relative permeability in the filter cake and formation, and exhibit good fluid-loss control. The water-base fluid often contains guar or HPG as viscosifiers which further enhance the fluid-loss properties of the emulsion. Laboratory testing has shown that J451 at a concentration of 5 gal/1000 gal is as effective as U51 at a concentration of 50 gal/1000 gal. Using J451 instead of U51 will be an economic benefit for the client because the diesel cost, transportation cost, and additional pumping cost are not incurred. Static testing and dynamic flow testing of 5% diesel as a fluid-loss additive have demonstrated different results. In a static test, the 5% diesel reduced the fluid-loss rate by a factor of 5. In a dynamic flow test, the reduction was only a factor of 1.5. A possible explanation for the difference is that the dynamic filter cake containing oil is very thin compared to one without oil, indicating oil has a detrimental effect on filtercake durability and thickness.



5 Formation Considerations The rate of fluid loss and the effectiveness of the fluid-loss materials depend on certain formation characteristics. Loss may be to the matrix or fissures or both. 5.1 Fluid Loss to the Rock Matrix If the fluid contains particulates of the proper size, these particulates will bridge pores at the fracture face and enhance the formation of the filter cake. Pore size and distribution in the rock matrix vary. Lower permeability formations generally have smaller pore openings. A 0.1-md rock may have an average pore diameter of less than 1.0 µm, while a 500-md rock may have an average pore diameter of 20 µm. The range of pore sizes may be quite large, which makes it beneficial to have a wide range of particle sizes so that all pore spaces can be bridged. The ground silica materials (J84, J418) and oil-soluble resin (J168) can be used to control fluid loss to the matrix.



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The SUPER SANDFRAC* K-1 fluid is a water-in-oil emulsion (67% oil and 33% water, stabilized with an emulsifier). Because it is an emulsion, K-1 has good fluidloss characteristics that can be further enhanced by the addition of J84 or J418. Water-base fluids containing J451 or U51 are also very effective controlling fluid loss to the rock matrix. Foam fracturing fluids are considered wall-building fluids when polymers are part of the liquid phase. The Cw for a foam is a combination of the liquid and gas leakoff velocities. Cw increases with permeability while Sp is zero at all permeabilities. Cw decreases as polymer concentration increases in the liquid phase. Foam quality (volume of the gas divided by the total volume) has little effect on Cw in low permeability (10 md. 5.1.1 Pore-Size Determination Pore-throat diameter can be determined (1) experimentally or (2) by calculation. 5.1.1.1 Experimentally Pore-throat diameter can be determined by mercury injection into a core sample. This method is destructive; the core cannot be used for any further testing. Alternatively, thin-section analysis can be performed on a small core section. 5.1.1.2 Calculation A representative pore-throat diameter can be calculated using Eq. 7 and permeability and porosity data. This calculated pore-throat diameter is not the average porethroat diameter, but is the pore-throat diameter that corresponds to the entry capillary pressure (the expression stresses that most of the flow, and therefore, most of the contribution to permeability, is occurring in relatively large pores).  k 1/ 2   = d 0.475  φR 



(7)



Where: d = pore-throat diameter (micron) k = permeability (md)



φr = porosity (decimal) 5.2 Fluid Loss to Fissures Controlling fluid loss to fissures that intersect the main fracture is more difficult than controlling fluid loss to the matrix because the openings to be blocked are larger. *



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Fissures can dramatically increase the permeability of the formation. Inert materials such as silica flour which can bridge the fissure and plug it off are used, but their effectiveness depends on the width of the intersecting fissure. Laboratory testing to compare the relative fluid flow through simulated fissures indicates that a fluid-loss additive is most effective at bridging these fissures when at least 60% of the material is composed of particles that are larger than the fissure width. Silica flour smaller than 200 mesh (J418) is very useful for microfissures (fissures less than 50 µm [0.002 in.] in width), but particles larger than 200 mesh (J84, 100-mesh sand) are necessary for macrofissures (fissures greater than 50 µm [0.002 in.] in width). Particulates in different mesh sizes are also available as oil-soluble resins. J168 is effective in microfissures, while J426 is more effective in macrofissures. Table 1 illustrates the influence of fissures in low-permeability rock.



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Table 1. Influence Of Natural Fissures In Low-Permeability Rock Average Permeability (md) as Influenced by Fissure of Given Width (in.) Fissure Interval (ft)



0.0005



0.001



0.002



0.005



0.010



0.5



1.23



9.10



73



1126



9000



1.0



0.66



4.60



37



563



4500



2.0



0.38



2.35



19



282



2250



5.0



0.21



1.00



8



113



900



10.0



0.16



0.55



4



57



450



20.0



0.13



0.33



2



29



225



50.0



0.11



0.19



1



12



90



100.0



0.11



0.15



1



6



45



0.5



1.62



9.50



73



1126



9000



1.0



1.06



5.00



37



563



4500



2.0



0.78



2.75



19



282



,250



5.0



0.61



1.40



8



113



900



10.0



0.56



0.95



4



57



450



20.0



0.53



0.73



2



29



225



50.0



0.51



0.59



1



12



90



100.0



0.51



0.55



1



6



45



0.5



2.13



10.00



73



1126



,001



1.0



1.56



5.50



37



564



4501



2.0



1.28



3.25



19



282



,251



5.0



1.11



1.90



8



114



901



10.0



1.06



1.45



5



57



451



20.0



1.03



1.23



3



29



226



50.0



1.01



1.09



2



12



91



100.0



1.51



1.05



1



7



46



0.1-md Matrix



0.5-md Matrix



1.0-md Matrix



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The influence of fissures on the average permeability of the fracture face is determined using Eq. 8 and demonstrated in the example. k avg = k md +



( 4.54)(10 9 )( w 3 ) L



(8)



Where: kavg = average permeability of fracture face (md) kmd = primary permeability of matrix (md) w = microfracture width (in.) L = distance between microfractures (ft).



Example A core test indicates that a particular formation has a permeability of 0.1 md, but pressure-buildup tests indicate that the formation has an average permeability between 0.3 to 0.4 md. The formation is obviously producing from fissures. Data in indicate the possible combinations of microfissure width and interval that would produce this much difference in measured permeability. This formation could possibly contain one 0.0005-in. fissure every 2.0 ft along the fracture face, or a 0.001-in. fissure every 20 ft.



6 In-Situ Measurement of Fluid-Loss Coefficients As part of the calibration treatment, the bottomhole pressure is monitored and recorded until fracture closure is attained. The data is analyzed using the G Plot in the DataFRAC* module of the FracCADE* software (Fig. 6). The slope of the G Plot and compliance determine the fluid-loss coefficient. DataFRAC Service provides additional discussion on pressure decline analysis following a calibration treatment.



Fig. 6. Idealized G Plot (from the DataFRAC software). *



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7 Guide to Dowell Fluid-Loss Additives Table 2 provides a guide to Dowell fluid-loss additives. This selection guide should be considered as general recommendation. Fluid-loss additives must be engineered considering the reservoir characteristics and the desired performance of the treatment.



Table 2. Guide To Dowell Fluid-Loss Additives Additive J66S



Composition Fine Salt



Solubility Water



Carrier Fluid Oil-base fluids or saturated brine



J84



Silica Flour



Inert



Water-base or oil-base fluids



J110



Colloids, Polymers Aluminosilicate and Fatty Acid



Inert



Water-base or oil-base fluids Oil-base fluids (uncrosslinked)



J126



Inert



J168



Hydrocarbon Resins



Oil



Water-base fluids



J237A



Liquid, Nonionic Resins Hydrocarbon Resins Liquid-Anionic Resins Silica Flour



Oil



Water-base fluids



Oil



Water-base fluids



Oil



Water-base fluids



Inert



Hydrocarbon Resins Proprietary



Water-base fluids Solvent



J238 J330 J418



J426 J451 J478



Polymers (starch)



S100



Silica



U51



Diesel Oil



Water



Inert Solvent



Water-base or oil-base fluids Oil Water-base guar or HPG crosslinked fluids Water-base fluids (oildispersible) Water-base or oil-base fluids Water-base fluids



DOWELL CONFIDENTIAL



Recommended Use and Quantity Designed for macrofissures. 0.25 to 2 lbm/gal Matrix, microfissure and macrofissure control, 10 to 35 lbm/1000 gal Matrix control, 25 to 50 lbm/1000 gal Matrix and microfissure control, 25 to 50 lbm/1000 gal Matrix and microfissure control, 20 to 100 lbm/1000 gal 30 to 50 gal/1000 gal



Matrix control, 20 to 50 lbm/1000 gal 6 to 24 gal/1000 gal Matrix and microfissure control, 10 to 25 lbm/1000 gal Macrofissure control, 25 to 300 lbm/1000 gal Matrix control, 5 gal/1000 gal Matrix, microfissure and macrofissure control, 25 to 50 lbm/1000 gal Macrofissure control, 10 to 35 lbm/1000 gal Matrix control, 5% of total fluid volume



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7.1 Fluid-Loss Additive Sizing Fluid-loss additives must be carefully selected to avoid invasion or plugging problems. Particles that invade are those where the particle diameter is less than one-sixth of the pore-throat size. Particles that plug are those where the particle diameter is greater than one-half of the pore-throat size. Particles that bridge are those where the particle diameter is greater than one-sixth of the pore-throat size but less than one-half of the pore-throat size. Particle-size selection may be determined using Fig. 7 if the pore-throat size is known or Fig. 8 if the approximate permeability is known.



Fig. 7. Bridging particle size versus pore-throat diameter.



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Fig. 8. Bridging particle size versus approximate permeability.



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APPENDIX F - EQUIPMENT 1 Introductory Summary............................................................................................................. 2 2 Mixing and Blending Equipment ............................................................................................ 4 2.1 PCM Precision Continuous Mixer ........................................................................................ 4 2.2 POD Blender ........................................................................................................................ 5 2.2.1 POD II Blender............................................................................................................ 7 3 Pumping Equipment ................................................................................................................ 9 3.1 Pump Application Guidelines ............................................................................................... 9 3.1.1 Fracturing Fluid Viscosity............................................................................................ 9 3.1.2 Slurried Fluids Containing Proppant ........................................................................... 9 3.1.3 Proppant Concentration and Low Pump Speeds...................................................... 10 3.1.4 High Vapor Pressure Fracturing Fluids..................................................................... 10 3.1.5 Volumetric Efficiency ................................................................................................ 11 3.2 Nitrogen ............................................................................................................................. 11 3.3 Carbon Dioxide .................................................................................................................. 12 3.4 Pressure Multipliers ........................................................................................................... 12 4 Treating Equipment ............................................................................................................... 12 5 Sensors................................................................................................................................... 13 6 Computing and Monitoring Equipment ............................................................................... 13 6.1 PACR Pumping, Acidizing, Cementing Recorder............................................................... 13 6.2 PPR Pumping Parameter Recorder ................................................................................... 13 6.3 FCS Computer System ...................................................................................................... 13 6.4 PAC Portable Acquisition Computer .................................................................................. 13 6.5 JMU Job Management Unit ............................................................................................... 14 7 Tools ....................................................................................................................................... 15



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8 Support Equipment ................................................................................................................15 FIGURES Fig. 1. Equipment positioning for a fracturing treatment (typical). ................................................3 Fig. 2. The RampFRAC Service. ..................................................................................................5 Fig. 3. The stairstep method of proppant addition. .......................................................................6



1 Introductory Summary Precision operation and dependability are two key factors in fracturing treatments. They are necessary to ensure that the treatment is executed as designed or can be modified in a controlled manner as dictated by well response. Several types of equipment are necessary to successfully perform a fracturing treatment. These are: • mixing and blending equipment •



pumping equipment



•



treating equipment



•



sensors



•



computing and monitoring equipment



•



tools



•



support equipment.



Fig. 1 (not to scale) illustrates the equipment positioning for a fracturing treatment on a land location. The type and quantity of equipment is dependent on many variables. Fig. 1 is for illustrative purposes only.



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Fig. 1. Equipment positioning for a fracturing treatment (typical). DOWELL CONFIDENTIAL



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2 Mixing and Blending Equipment Fracturing fluids, liquid- and dry-additives, and proppants are combined, thoroughly mixed, and discharged using mixing and blending equipment. 2.1 PCM Precision Continuous Mixer The PCM* precision continuous mixer is a pumping and blending system that allows continuous mixing of fracturing fluid. Water-base fracturing fluids with equivalent polymer concentrations of 10 to 60 lbm/1000 gal can be continuously mixed and discharged at a maximum of 70 bbl/min. Equipment consists of •



a 1500-gal liquid polymer-slurry tank (1500 gallons of polymer slurry will make 160,000 gal of WF40)



•



a 10,000-gal, six-compartment reactor (for polymer hydration)



•



a potassium chloride (KCl) additive system (rates up to 12 bbl/min)



•



three liquid-additive systems with a storage capacity of 345 gal each (rates up to 15 gal/min)



•



one slurry-additive system with a storage capacity of 345 gal (rates up to 15 gal/min).



All systems are redundant. All additive rates may be automatically or manually adjusted. The values for fluid and additive rates, pH, temperature, conductivity and viscosity are monitored and output to the TCV* treatment control vehicle or JMU job management unit.



Limitations of Application The PCM mixer has open-topped tanks containing agitators and cannot be used for mixing oil-base fluids. An explosive oil-base cloud formed over the tanks could easily result in a huge location fire. Acid-base fluids should not be introduced into the PCM mixer. The PCM mixer is manufactured with numerous aluminum components (for example, impellers, shafts, and brackets) that are incompatible with acid-base fluids.



References General specifications for the PCM mixer are provided in the Equipment Catalog. Detailed PCM mixer information is provided in the SBF211 Operators Manual.



*



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2.2 POD Blender The POD∗ programmable optimum density blender uses process-control computers to meter the precise proppant-to-fluid ratios throughout the treatment, strictly adhering to the treatment design parameters. This precision blending capability is ideal for the RampFRAC* service, considered ideal for optimum proppant placement (Fig. 2).



Fig. 2. The RampFRAC Service. THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY The POD blender can accurately mix and meter proppant, dry additives, liquid additives and fracturing fluid together at a specified density in the pre-programmed ∗



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automatic mode. Equally precise metering can be handled from the command console (truck only) or from the remote-control panel. Response time is minimized because signals from the integral rapid-response densitometer are routed directly to the microprocessor controlling proppant addition. Normal response time to a change in proppant concentration is less than 10 sec, regardless of pump rate. This immediate response time permits accurate and quick proppant addition necessary for a stairstep treatment design (Fig. 3).



Fig. 3. The stairstep method of proppant addition. THIS FIGURE IS FOR ILLUSTRATIVE PURPOSES ONLY The proppant concentration can be precisely and safely controlled up to 22 PPA (sand) and 32 PPA (high-strength proppant). Overall proppant/fluid ratio is constantly monitored and controlled in a range of ± 0.5%. DOWELL CONFIDENTIAL



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Additionally, the central processing unit maintains discharge pressure at a constant value to ensure adequate net positive suction pressure at the high-pressure, reciprocating-pump suction manifolds. The POD blender can be truck-mounted or skid mounted. The truck-mounted, remote-controlled POD blender is capable of blending and pumping slurry at 70 bbl/min and 100 psi. Equipment consists of • two independent vortex mixers •



microprocessor-controlled integral gates to meter the proppant



•



two microprocessor-controlled liquid-additive pumps (0.5 to 6 gal/min each)



•



one microprocessor-controlled liquid-additive pump (0.5 to 10 gal/min)



•



two microprocessor-controlled dry-additive systems (0.009 to 0.640 ft3/min each)



•



a tank for liquid-additive storage.



The skid-mounted, remote-controlled POD blender is capable of blending and pumping slurry at 35 bbl/min and 100 psi. Equipment consists of • a vortex mixer •



a microprocessor-controlled integral gate to meter the propping agent



•



a single-piece skid with a crashframe.



References General specifications for the POD blenders are provided in the Equipment Catalog. Detailed truck-mounted POD blender information is provided in the SBT611 Operators Manual. Detailed skid-mounted POD blender information is provided in the SBS611 Operators Manual. 2.2.1 POD II Blender Like the POD blender, the POD II blender is equipped with two independent vortex mixers with microprocessor-controlled integral gates to meter the proppant. Additionally, the POD II blender has the following improvements:



*



•



Communication  The POD II blender will communicate with a PPR* pumping parameter recorder or a PAC* portable acquisition computer.



•



Suction and discharge process flowmeters  Flow rate information is communicated side-to-side and to the data acquisition system. Pump rate and volume calculation no longer depend on high-pressure pump efficiency. With the flow rate known, additives can be set to run in the concentration mode. Since both sides know total flow, additive systems on either side can meter according to the total unit flow.



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Liquid-additive system  The liquid-additive pumps are stainless-steel pumps. The pump-rate range is 1 to 35 gal/min and the pumps can pump slurries. Nonintrusive, coriolis flowmeters are used to measure flow rate and are much more accurate than turbine flowmeters. The liquid-additive system has a great deal of functional redundancy, including calibration tanks similar to the tanks on the PCM mixer and prejob calibration of tachometer rates to the flowmeters. The POD II blender can meter liquid additives based on fluid density rather than fluid rate. This means that as the liquid rate decreases (the proppant concentration increases), the liquid-additive rates ramp-down with the fluid rate (RampADD* Service). This provides a consistent fluid quality instead of a stepwise quality. The FracCAT∗ Service system-software sends concentration set-points and can use this feature. The PPR software sends rate set-points and cannot use this feature.



∗



•



Dry-additive system  The POD II blender can meter dry additives based on fluid density rather than fluid rate. This means that as the liquid rate decreases (the proppant concentration increases), the dry-additive rates ramp-down with the fluid rate. Dry-additive rates are established by entering the desired screw factor directly into the control panel as opposed to running on speed (rpm). The concentration can also be ramped using the FracCAT software.



•



Standard remote display (SRD)  The POD II blender has incorporated all functions into the SRD. This is the same SRD used with the PAC computer, but configured differently for the blender. The operator switches screens to interact with different parts of the software such as self-diagnostics, maintenance tracking or total volumes pumped. The SRD is programmable.



•



Density measuremen t Density calculation routines are incorporated in the POD II blender software. The densitometers are calibrated and zeroed using the control panel.



•



Density control  Ramps can now start at zero density. If a densitometer fails, the density is calculated using the flowmeters. If a flowmeter fails, old methods of density control automatically take over.



•



Self-diagnostics  Self-diagnostics provide real-time information during the job if the software suspects equipment problems, allowing the operator to take corrective action. Before the job, the unit will inform the operator if calibrations (for example, densitometer calibration) have changed from previous values, indicating possible problems. Material quantities (for example, total proppant pumped) are recorded to aid in mechanical maintenance such as slinger wear. A unit “health check” can be performed using a built-in self-test procedure. Mechanical and electrical components (including sensors) are exercised while the software searches for anomalies.



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3 Pumping Equipment High-pressure pumping equipment provides the necessary horsepower to create and propagate the fracture. Fracturing fluid is pumped with reciprocating pumps. A reciprocating pump is a mechanical device used to impart a pulsating, dynamic flow to a liquid and consists of one or more single- or double-acting positive displacement elements (pistons or plungers). The elements in the fluid end are driven in harmonic motion by a slider crank mechanism. The liquid flow generated by this reciprocating motion is directed from the pump inlet (suction) to the pump outlet (discharge) by the selective operation of self-acting check valves located at the inlet and outlet of each displacement element. The reciprocating pumps used by Dowell are single-acting triplex (three cylinder) and quintiplex (five cylinder) pumps. Diesel and turbine engines are used to provide power to operate the pumps. 3.1 Pump Application Guidelines 3.1.1 Fracturing Fluid Viscosity The limited amount of available literature in pump textbooks and handbooks on reciprocating pump performance invariably limits the discussion to water (viscosity of 1 cp). Unfortunately, low-viscosity fracturing fluids are rarely used. In general, very limited testing indicates that the viscosities typically encountered in linear fracturing fluids do not have a significant effect on pump performance. 3.1.2 Slurried Fluids Containing Proppant Limited testing with Dowell pumps has been performed to determine the effect of proppant concentration on pump performance. Testing has been limited to waterbase fracturing fluids containing sand as a proppant. The testing has revealed that valve dynamics can be extremely sensitive to proppant concentration. The poor pump performance manifests itself as rough running or line shake. As such, it can easily be mis-diagnosed as cavitation; however, poor pump performance at relatively high proppant rates and pump speeds (when suction pressure is adequate) may be caused by delayed closure or “valve float.” Modification of pump valves and springs has improved the slurry handling capabilities of some pumps. Testing with the QL and QI quintiplex pumps has indicated a maximum proppant concentration of 13 PPA at 20 bbl/min. The maximum proppant concentration is reduced to 3 PPA at 29 bbl/min. Limitations exist for all Dowell pumps; however additional testing has not been performed.



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3.1.3 Proppant Concentration and Low Pump Speeds The addition of a recirculation line to suction manifolds on stimulation units pumping high proppant concentrations at low pump speeds is customary. A recirculation line increases the mean fluid velocity through the suction system by the recirculation of a portion of the flow back to the blender. This decreases the tendency of the proppant to settle in the pump suction header. If sufficient proppant does settle in the suction header, the belief is that slugs of proppant can be ingested by the pump, totally blocking one or more cylinders. Proppant settling will be worst at the cylinder farthest from the suction header inlet. Although the velocity profiles in the suction line and header are known, the actual mechanism of proppant packing in the pump is not well understood. The proppant settling, to some extent, is self-compensating. As proppant settles, the conduit cross sectional area is reduced which increases mean velocities and reduces the tendency of the proppant to settle. Field practice varies widely as to determination of when to use a recirculation line. Factors to consider are • pump speed •



mean suction velocity



•



fluid properties



•



proppant type



•



proppant concentration.



The practice is most prevalent when proppant concentrations exceed 10 lbm proppant added and pump speed is less than 150 rpm. 3.1.4 High Vapor Pressure Fracturing Fluids High vapor pressure fracturing fluids reduce the available net positive suction head to the pump. Parameters to consider are •



Water-base fluids at high temperature. The vapor pressure of water rapidly rises when the fluid temperature exceeds 140°F (60°C).



•



Inflammable or combustible fluids. A requirement of Dowell Location Safety Standard 5 is to determine the vapor pressure of fracturing fluids containing oil, condensate, alcohol or solvent(s) prior to use. Generally, the vapor pressure of these fluids will not significantly reduce the net positive suction head available.



•



Carbon dioxide (CO2). The vapor pressure of CO2 at -109°F (-43°C) is one atmosphere. Carbon dioxide will revert to the vapor phase in normal pumping conditions. Therefore, CO2 is pumped at high (suction) pressure (300 to 350 PSIG) to ensure that no vapor phase exists or can easily form. A special CO2 suction header is installed on the pump and must be used when pumping CO2.



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3.1.5 Volumetric Efficiency Reciprocating pumps never achieve theoretical flow rates for two reasons. 1. Operational inefficiencies (cavitation and valve float) in the pump. When operating under conditions of cavitation or valve float, discrepancies will always arise between mechanical barrel counters and actual flows. 2. Fracturing fluid compressibility. Fluid compressibility is an intrinsic property of fluid and is unavoidable. Volumetric efficiency is the ratio of the actual flow rate to the theoretical flow rate. Most Dowell mechanical barrel counters are calibrated assuming a volumetric efficiency of 97%. Volumetric efficiencies are usually not a concern in the majority of Dowell services.



References Additional information is provided in the Reciprocating Pump Application Manual and Dowell Location Safety Standards. Fluid end ratings and constants are provided in the Treating Equipment Manual. 3.2 Nitrogen Nitrogen (N2) is delivered to the wellsite in a liquid state at -320°F (-196°C) and must be vaporized before being pumped. A centrifugal pump feeds the liquid nitrogen to a high pressure reciprocating pump. The reciprocating pump, in turn, pumps the liquid nitrogen through a vaporizer (heat exchanger). The vaporizer converts the liquid nitrogen to a gas and heats it to 80 to 100°F (27 to 38°C). The vaporizer may be either a diesel-fired unit or a (flameless) water brake. Diesel-fired equipment may be used where local regulations permit operation. Flameless equipment is used offshore. Another type of nitrogen equipment is the Pressure Swing Adsorption (PSA) unit. This equipment allows onsite generation of high-pressure nitrogen gas drawn from ambient air. This is advantageous when liquid nitrogen is difficult to obtain or in remote areas. A disadvantage of PSA equipment is the low discharge rate (approximately 650 scf/M at 5000 psi). Nitrogen pumping equipment may be either truck- or skid mounted.



References General descriptions and specifications for nitrogen pumping equipment are provided in the Equipment Catalog. Safety information is provided in the Dowell Location Safety Standards.



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3.3 Carbon Dioxide Carbon dioxide (CO2) is delivered to the wellsite in a liquid state at 0°F (-18°C). Unlike nitrogen, carbon dioxide is not converted to a gas and preheated before being pumped. A centrifugal pump (CO2 booster pump) feeds the liquid carbon dioxide at 300 to 350 psi to conventional reciprocating pumps equipped with a special suction manifold. Carbon dioxide pumping equipment may be either truck- or skid mounted.



References Additional information is provided in the Dowell Location Safety Standards. 3.4 Pressure Multipliers Pressure multipliers are intended to operate at treating pressures from 10,000 to 20,000 psi for long periods of time (greater than two hours). The pressure multiplier is equipped with a duplex pump and is powered with a turbine engine. The duplex pumps have a stroke of 70 in. or more. This allows fewer pump strokes and valve cycles per volume of fluid pumped and greatly prolongs pump life.



4 Treating Equipment Treating equipment is the equipment, other than trucks or skids that is used to execute a fracturing treatment. Treating equipment includes • swivel joints •



valves



•



treating adapters



•



pipes and loops



•



hose and fittings



•



ball injectors



•



fracturing heads



•



fluid ends



•



tree savers (wellhead protectors).



Dispersers, quick disconnects and other miscellaneous equipment are also treating equipment.



References Comprehensive information for the maintenance and operation of treating equipment is provided in the Treating Equipment Manual. Safety and use information is provided in the Dowell Location Safety Standards.



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5 Sensors A sensor provides the result, or, “measured data” in the form of an analog signal. Examples of measured data are the wellhead pressure, pump rate and slurry density. Measured data are used to provide “calculated data.” Examples of calculated data are bottomhole pressure, volume and proppant concentration.



References Comprehensive information for the maintenance and operation of sensors is provided in the Sensor Engineering Manual and the Sensor Verification Manual. Additional information is provided in the various operation and technical manuals for sensors.



6 Computing and Monitoring Equipment The fracturing treatment effectiveness is greatly enhanced by using computing and monitoring equipment to process and evaluate treatment parameters before, during and after the fracturing treatment. 6.1 PACR Pumping, Acidizing, Cementing Recorder The PACR* pumping, acidizing, cementing recorder is a portable data acquisition system that monitors and records sensor signals at the wellsite during pumping operations. 6.2 PPR Pumping Parameter Recorder The PPR pumping parameter recorder is a portable stimulation process monitoring and control system. The PPR allows the mobile deployment of microprocessor-base equipment used to monitor, evaluate and control well treatments. 6.3 FCS Computer System The FCS computer system is based on the MicroVAX+ hardware and allows the mobile deployment of a computer to support the CADE* Computer-Aided Design and Evaluation software. 6.4 PAC Portable Acquisition Computer The PAC portable acquisition computer is a standalone acquisition system with a Standard Remote Display (SRD). It is primarily used as a front-end acquisition system that supplies job-related data to Dowell wellsite control, reporting and analysis systems (Wellsite Reporting System [WRS] software or FracCAT Service system-software. The PAC computer is a ruggedized unit that acquires data from all Dowell equipment and certified sensors. It can easily connect with, and monitor, * +



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additional sensors that utilize standardized petroleum industry output signals. The SRD allows an operator to quickly program, calibrate and operate the acquisition computer while monitoring job parameters in real time. The PAC computer can send up to 40 parameters to a Dowell Wellsite Reporting System (WRS) or to a client's personal computer. When used in conjunction with the FracCAT Service, the PAC computer completes the communications loop between Dowell process-control equipment and the analysis computers. Acting like a bridge, the PAC computer allows commands from the analysis computer to reach the process-control equipment. This equipment carries out the designated commands, then reports back to the analysis computer (via the PAC computer). The PAC computer has a NEMA-4X (IP65) water and dust protection rating and battery backup for internal RAM memory. The operating temperature ranges from 20 to 70°C (-4 to 158°F). PAC computer features are • supports oilfield, Canadian metric and French metric units • communicates with Dowell process-control equipment (POD Blender, VIP* Mixer and CLAS* system) • an external mass-storage drive which uses removable memory-card technology is optional • no moving parts in either the acquisition computer or the optional external storage drive • accepts up to 60 inputs (sensors) • compatible with existing Dowell sensors (standard and custom) • pressure and density are updated at a 2-Hz rate • can accept bottomhole pressure and bottomhole temperature measurements from all major wireline companies • user-selectable record rate from 0.5 to 10 sec • recorded data can be played back • postjob corrections can be applied and played back if a sensor's original setup was not correct • self-guiding, troubleshooting program is built into the system • the PAC computer is portable, but may be permanently mounted. 6.5 JMU Job Management Unit The JMU job management unit allows the mobile, onsite deployment of the FracCAT Service. The client can use the FracCAT Service system-software in the JMU. Externally, the JMU resembles the TCV treatment control vehicle. Internally, the JMU is divided into management and operator compartments. The management *



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compartment, or client/service supervisor area, houses the treatment control hardware and software. Five people can be comfortably seated, and a total of 10 people may be accommodated in the management area to observe and use the FracCAT software. The operator compartment is arranged so that equipment operators can maintain eye and voice contact with the Dowell service supervisor. Six remote-control panels (expandable to nine) can be placed into the operator compartment. An uniterruptible power supply assures continued operation in the unlikely event that the direct-drive AC generator fails.



References General specifications for computing and monitoring equipment are provided in the Equipment Catalog. Additional information is provided in the Sensor Verification Manual, Sensor Engineering Manual, FracCADE User Manual, Wellsite Reporting System User's Manual, and the various operation and technical manuals for computing and monitoring equipment.



7 Tools Packers and bridge plugs are mechanical devices used to protect casing strings and divert fracturing fluid. Methodology is provided in Diverting Techniques. Additional information is provided in the Downhole Tools Hydraulic Manual and the Retrievable Tools Technical Manual. General specifications for tools are provided in the Equipment Catalog.



8 Support Equipment Support equipment is the equipment used for handling materials. equipment includes • liquid-transport trailers • transfer pumps • manifolds • dry-material transports • dump trucks • proppant feeders • proppant conveyers • utility trucks • portable tanks.



Support



General descriptions and specifications for support equipment are provided in the Equipment Catalog.



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