Advanced OilWell DrillingEngineering (Mitchell) [PDF]

Citation preview

OILWELL DRILLING ENGINEERING &



computer programs



MITCHELL



©Copyright. USA Library of Congress, 1974 to Mitchell Engineering



10th EditioQ, 1st Revision, July 1995 Dr. Bill Mitchell MITCHELL ENGINEERING 12299 West New Mexico Place Lakewood, CO 80228, USA Email: [email protected] Tel#: 303 9867453 USA All rights reserved. This book or any part thereof must not be reproduced in any form without the written consent of MITCHELL ENGINEERING. Printed in the United States of America.



For additional copies contact: The Society ofPetroleum Engineers of the AIME, PO Box 833836, Richardson, Texas, 75083-3836, USA. Tel#: 9729529393 Fax#: 972 952 9435 Email: [email protected]



TABLE OF CONTENTS ClIAP'IER I 'IUBl.JIAR DESIGN .AND USE Tubular Design and use ; Failure Theories Tubular End Conditions Names of Casings Loads Salt and Diaperic Shale Casing Design Criteria Management s Guidelines Popular Desigri Factors : Drilling Burst Criteria An Overview of Casing Selection Minimum Tubular Strengths: Failure Mode Triaxial Equation Real Gas Fundamentals of Tubulars Stress Analysis Effective Tension Buoyed Weight Free Bodies Stretch and Wall Strains Change in the Diameter of a Tube Bending Stress in Doglegs Lubinski Bending Stress Buckling v. Tension & Compression Critical Buckling Events of Casing Buckling Tendency & Wellhead Load Intermediate Casing Design Tubular Strengths API Collapse Resistance API Internal Pressure Resistance Pipe Body Yield Strength API Hydrostatic Test Pressures Tolerances on Dimensions Make-up Torque for API Couplings Round Thread with Bending and Tension Tubular Connections Slack-off Bending Loads Surface Running Loads Dogleg Running Loads Tubing Design Drillpipe Design Combined Tension, Torsion, Bending & Pressure Loads Von Mises Stress Slip Crushing



1 l



1 1 2 2 6 7 7 11 11 13 14 15 16 2O 22 CZ7



,



I



TABLE OF CONTENTS



1



ro



31 34 41 .41 49 49 53 54 57 63 68 OO 75 79 82 83 86 86 89 OO 92 92 $



,



1fJ7 108 108 116



MITCHELL Box 1492 Golden CO 80402



Fatigue of Drillpipe Life of Drillpipe Casing Tally Casing Centralizer Spacing Casing Sag between Centralizers Wall Force Equation Helical Buckled pipe length



,



117 121 122 125 127 129 130



CHAPTER n DRJI,IJNG OPTIMIZATION METHODS Cost per foot Equation Time Value of Money Expected Value Method Lagrangian Multiplier Multiple Regression with Least Squares Confidence Lines Lagrange's Interpolation Formula



144 144 147 148 153 156 100 162



CHAPTER III DRILL HOLE MECHANICS Selecting Casing Setting depths Stresses around a Drill Hole Leakoff Test ' Fractures in a Drill Hole· Fracture Gradient Plot Filtration of Mud into the Formation Barite & Water required to drill a Section of Hole Solids Concentration Selection



I64 165 168 171 174 180 182 183 185



ClIAPrER IV KICK REMOVAL .••..•..••...••..•.•.•.••••..•••.••..•..•.•...•..••••.•192 197 Kill Parameters Initial Conditions 197 Drillers Method 199 Engineer's Method 204 Kick Control Worksheet 210 Gas Migration 217 Recognition 223 High Weight Pill 223 Barite Plug W Filling the Hole on Trips ..' 228 Novel Techniques 229



CHAP'rER V RIG HYDRA~ICS .•...•....••••.••••....•••••.••.••.•........•.....•.•zra Effect of Mud Weight on Bit Hydraulics 243 Bingham's Drilling efficiency Diagram 246 Optimal Bottom Hole Cleaning 249 Theory of Maximizing Impact Force 259 Effect of Mud Weight of Bit Hydraulics 261 Hole Cleaning 262 Drill Cuttings concentration in the Annulus 264 Hopkin's Particle Slip Velocity Chart 267



TABLE OF CONTENTS



11



MITCHELL Box 1492 Golden CO 80402



Oribital Motion of the Drill String Surge and Swab for Long Pipe Strings Surge and Swab Pressures of Short Tools Circulating Pressures for Short Tools Equivalent Circulating Density



CHAPTER VI DffiECTIONAL DRaLING Directional Drilling Directional well planning Transposing MD to TVD Tie Point and Collision Kill Well Design Leading the Target with planned walk Dogleg Severity of Holes Dogleg-abrupt '" Wilson's Equation Monitoring of a Directional Well Radius of Curvature Sectional Method and Minimum Curvature Stability of Computational Surveys Errors in Surveying Ellipse of Uncertainty Systematic and Random Errors by Warren Circle of Uncertainty Declination Changes Drilling String Measurements Magnetic and other Interferences Hot Spots in BHA People Recording Errors 3 Dimensional Drill Hole Planning Tool Face Rotation CIlAP"IER vn HORIZONrAL DRll.LING Uses of Horizontal Well Horizontal Drilling Types of Horizontal Wells Horizontal Well Costs Casing & Drill bit sizes Equipment Directional Drilling subs and stabilizers Bottom Hole Assemblies Length of non-magnetic Drill collars Trajectory Planning Vertical Turn to aNew Track Selection of Mud Weights Drill bit Hydraulics Torque and Drag Friction factors Buckling of the Drill String



TABLE OF CONTENTS



111



274 276 285 2i57



289 292



292 2fJ7



306 310 314 316 319 32D 322 325 327 331 338 343 343 346 347 350 350 351 352 353 355 359



:



,



,



3m 373 373 374 376 378 381 384 386 388 3OO



3m



399 403 405 409 .414



MITCHELL Box 1492 Golden CO 80402



Lock-up of the Drill String Available Torque for the Drill bit Cementing Problems Cement Sheath within Casing Conveyed Logging Case Histories Austin Chalk Well Tyra field offshore Denmark



.415 .415 .418 .418 419



420 420 422



CHAPTER VIII BOTTOM HOLE ASSEMBLIES...........•...........•....•.....427 Purpose of BHA 4Zl Type of BHS's 4Zl Discussion of Components , 429 Mechanical Properties of BHA 432 Tapered . BHA 436 U sable Hole Diameter 438 Centrifugal Force : 440 Torsional Dampening 441 Torque of a Spinning BHA 442 Torsional Buckling of a BRA and Drillpipe 443 Buckling by Rotational Drag 445 Critical Buckling Load 446 Weight on Drill bit in Veritcal and Inclined Holes 447 Critical Rotary Speeds of BHA .450 Placement of the Pendulum Stabilizer 453 Packed BRA 458 Directional BHA 460 BHA Connections 462 Make-up of Connections 464 Identification of Connections and Drillpipe 464 ClIAP'I"ER:IX. AIR DRII...LIN"G Advantages and Limitations of Air/Gas Air Drilling Equipment Pneumatics and Hydraulics Pressure Losses in Pipe and Fittings Air Temperature Increases on Compression Air Pressure Requirements Mist Drilling Volumes and Pressure Requirements Foam Drilling Volumes and Pressure Requirements Aerated Mud Volume and Pressure Requirements IKOKU Operational Procedures Concentric Drillpipe and the Jet Sub Parasite String Safety Practices



CHAPTER X CEMENT One Dozen Cementation Problems



TABLE OF CONTENTS



iv



~



467 4OO .476 .478 .480 481 486 486 488 488



489 .494 494 499 fj(l;



506



MITCHELL Box 1492 Golden CO 80402



Solutions to a Dozen Problems Balanced Plug Cementation Formula Cementation Temperatures



506 516 517



CHAPTER XI DRILL BIT SELECTION•...........•..........•.••...•.••...•..••....522 Drill Bit Characteristics 525 Rock Bit Terminology 5CZl Rock Failure Models 528 Drill Bit Selection Criteria 528 Trip Time 530 Optimal Weight on Bit Rotary Speeds 530 Contour Method 531 Analytical Method 533 Optimal WOB Rotary Speed Charts 539 Diamond Bit Hydraulic Lift Off 545 Dull Bit Grading 547 CIlAP'rER XII FISHIN"G Definitions To Fish or Not to Fish When to Stop Fishing Break-even Charts Expected Value Method Confidence Lines Least Squares Differential Sticking ; Mechanics of Differential Sticking Freeing Differentially Stuck Pipe Jars and Accelerators Back-off Free Point Free Point Procedures Free Point with Pipe Stretch Back-off Procedure Latching on to a Fish Overshot Specifications Milling Washover Pipe Rotary Shoes Perforation of Pipe Perforating Procedure Fishing Wire Line Tools Fishing small objects Fishing Drill Collars Fishing Drillpipe Back-off Depth Cutting of Tubulars Sidetracking Whipstock .. " " PDM snd Bent sub



TABLE OF CONTENTS



v



m> 551 ; 551 552 553 554 556 OO:> 00:>



,



561 566 569 569 569 569 571 573 574 575 578 578 580 581 582 585 586 586 5f57



588 589 ,..590 591



MITCHELL Box 1492 Golden CO 80402



Cement Plugs for Sidetrack Common Fishing Tools Bottom Hole Motor



591 593 597



I~][)~~ ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• ~



TABLE OF CONTENTS



VI



MITCHELL Box 1492 Golden CO 80402



CHAPTER I



TUBULAR DESIGN AND USE GENERAL



The axiom of tubular design is that the loads placed on a tube by natural phenomena must be offset by its strengths. There are many natural phenomena which could dictate a particular tubular design. Also, there are many theories for determining the strengths of a tube. The tubular designer must therefore derive practical design equations from the theories and phenomena. These equations represent the "criteria for tubular design". COlVfMON F~URE THEORY ASSUlVIPTIONS



The most common simplifying assumptions with regard to tubular strengths are that the failure theory known as the MAXIMUM STRAIN ENERGY OF DISTORTION THEORyl applies only to tubular collapse strengths and that only biaxial 2 loads are considered within the theory. Thus tensile loads and burst loads are thought to be uniaxial 3 and strengths are rationalized with the MAXIMUM PRINCIPAL STRESS THEORY OF FAILURE.4 Design factors are usually based on experience. 1 This theory predicts failure of a specimen subjected to any combination of loads when the portion of the strain energy per unit volume producing change of shape (as opposed to change of volume) reaches a failure determined by a uniaxial test. Refer to Strengths of Materials, by S. Timonshenko, reprint 1976, Krieger Publishing Company.



Biaxial loads are those which result in the material of a structure being subjected to the simultaneous action of tension or compression in two perpendicular directions. Reference same as above.



2



Uniaxial loads are those which result in the material of a structure being subjected to the action of tension or compression in one direction only. Reference same as above.



3



4 This theory predicts failure of a specimen subjected to any combination of normal and shear stresses when the maximum principal stress, which is the maximum normal stress acting on a set of perpendicular planes which have no shear stress acting on them, reaches a failure value determined by a uniaxial test. Reference same as above. TUBULAR END CONDITIONS



The ends of tubulars (top and bottom of the casing) may either be fixed or free. The bottom end is usually free until cemented and the top end is free until the wellhead slips are set. These conditions are tubular end conditions. The common TUBULAR DESIGN AND USE



1



MITCHELL Box 1492 Golden CO 80402



CHAPTER II



DRILLING OPTIMIZATION METHODS Drilling optimization is the application of technology which yields a reduction of drilling costs associated with making hole. The following optimization techniques are popular in drilling. 1. 2. 3. 4. 5. 6. 7.



Cost per foot equation Time value of money Expected value method Lagrangian multiplier Multiple regression Confidence intervals Lagrange's interpolation formula



COST PER FOOT EQUATION The cost per foot equation is used for the comparison of alternative equipment, chemicals, and procedures for the drilling of a formation or an interval. The comparisons are often called break-even calculations and are usually between drill bit types or manufacturers; however, any of the variables may be compared..



c _ Bit + Tools + Mud + [Drill Time + Trip + Lost] [Rig + Support + Tool Rental] Drill Rate * Drill Time C Bit Tools Mud Drill Time Trip Lost Rig Support Tool Rental Drill Rate



=Cost per foot for the interval of concern; $/ft =Cost of delivered bit at the drill site; $ = Cost of tools or repairs to tools; $ =Cost of mud to drill the interval; $ =Time required to drill the interval or bit life; hr = Time to pull and run a bit; hr = Time chargeable to non-drilling task; hr = Contract rental rate of a rig; $/hr = Third party contractors rates; $/hr = Rental of tools; $/hr = Average drilling rate over the interval; ftfhr



In a comparison of drill bits, the drilling rate and life of the proposed bit will always be in question. The usual procedure is to compute the cost per foot with the data from a standard bit with the proposed bit; and, then construct a chart of required drilling rate and bit life for the proposed bit. The following example illustrates the method.



DRILLING OPTIMIZATION METHODS



144



MITCHELL Box 1492 Golden CO 80402



CHAPTER III



DRILL HOLE MECHANICS INTRODUCTION Drill hole mechanics is the topic which aids most of all in the choice of a mud weight for drilling a section of hole. The choice of mud weights is one of the most analytically complex, political taxing, and critical task. The following list are those factors which may have an effect. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22.



Fracture gradients (there are two) Pore pressure Kick tolerance Casing shoe depths Borehole stability (sloughing formations) Surface pressure control equipment Annular circulating" pressures Pressure surges (swabbing and running pipe) Differential sticking of pipe Filtration of mud Filling of the hole Gas cutting of the mud Bit hydraulics Mud cost Drilling rate Removal of drill solids Formations porosity, permeability, and fluids Safety margin over the pore pressure Safety margin under the fracture gradients Electric log analyst Geologist (cuttings analysis) Reservoir engineering (formation damage)



DRILL HOLE MECHANICS



164



MITCHELL Box 1492 Golden CO 80402



CHAPTER IV



KICK REMOVAL The driller's and engineer's removal methods are two reliable methods of circulating a drilling kick from a hole. The other methods presented below are satisfactory in special circumstances. The depicting attributes of each method are the following: Driller's 1. kill mud is pumped after the kick is removed from the hole 2. two circulations of the hole are required 3. annular and surface pressures will be higher while removing the kick than those of the engineer's method



Engineer's 1. the drilling mud is weighted to kill mud weight prior to pumping 2. kill mud is pumped while removing the kick 3. one circulation is required to kill the hole



Concurrent 1. drilling mud is weighted as it is pumped into the hole but not necessarily to the weight of kill mud 2. the hole will contain a variable weight mud 3. annular and surface pressures will be higher than the engineer's and less than the driller's



Gas Migration 1. the gas bubble is allowed to rise in the annulus without circulating 2. the casing pressure is allowed to rise to a selected value without bleeding mud 3. mud is bled from the annulus while keeping the pressure at the selected value 4. after the kick rises to the surface, heavy mud is lubricated into the annulus to kill the annulus and well.



Dynamic 1. kill weight mud is pumped at a rate sufficient to raise the pressure at the bottom of the hole above or equal to that of the kicking formation. The increase in bottom hole pressure occurs because mud is occupying more and more of the volume of the



DRILLING OPTIMIZATION METHODS



192



MITCHELL BOX 1492 Golden CO USA



CHAPTER V



RIG HYDRAULICS OBJECTIVES



Objective of Rig hydraulics has eleven facets and one myth: 1. cleaning of the bottom of the hole while drilling



2. cleaning of the drill bit 3. transportation of solids to the surface at a reasonable rate 4. removal of drill solids and cavings with mud cleaning equipment



5. equivalent circulating density for the prevention of lost circulation 6. running of close clearance tools 7. circulating by close clearance tools 8. friction pressure losses through and around the drillstring and rig piping



9. hydraulic energy consumption and pressure drop through down hole tools within the drillstring 10. circulation of cement and completion fluids 11. surge and swab



12. holes do not wash out (This is the myth.) BASIC RIG HYDRAULIC EQUATION Pump Pressure



=



~Ppipe&ann



i lifts cuttings



+



~Pjets



+ i cleans bottom of hole and bit teeth



~Pmotor +



i turns bit



~Pliftoff



i diamond bits



+



~Ptools



i power for tools



MUD RHEOLOGY



Recall that the University of Tulsa data showed that a powerlaw Reynold's Number of 1,800 cleaned cuttings beds and prevented their accumulation in high angle holes.



RIG HYDRAULICS



232



MITCHELL Box 1492 Golden CO 80402



CHAPTER VI



DIRECTIONAL DRILLING INTRODUCTION Directional wells are defined as those wells which are to follow a prescribed traverse and intersect a specific objective. The objective is called a target and is usually an enclosed area in a horizontal plane. A target could be a circular area at the top of a producing zone. If tolerance in the deviations of the well from the planned traverse is critical, the traverse is usually specified as a cylinder surrounding a section of the hole; otherwise, the traverse is given as a line path between the rotary table and the target. Popular visual presentations of RTB 0 directional well data are on charts called U vertical horizontal and section views. The section view is a vertical cross-section drawn build radius through the centers of the rotary table and KOP 1 the target.



T



~



N



X build



8082



"



~Iantangle Y slant



B053



"



Zdrop



8004



target



The horizontal view depicts northsouth and east-west axis' which intersect B hang angle in the center of the rotary table. The target, the traverse, and directional BOH5 tvd stations are recorded on the two charts. The axis of the horizontal view may represent magnetic directions if it is desired. The primary purposes of the two views are to pictorially show deviations of the drilled traverse from the planned traverse and the progress of the hole relative to the target.



DIRECTIONAL DRILLING



292



MITCHELL Box 1492 Golden CO 80402



CHAPTER VII



HORIZONTAL DRILLING USES OF HORIZONTAL WELL Horizontal wells are directional wells drilled with an inclination angle near 90 degrees. The purposes of drilling horizontal wells are not new. However, the application of solid state electronics in directional drilling at long last permits the fulfillment of those purposes. The primary purposes of horizontal wells are the following: 1. Intersect many fractures in a hydrocarbon containing formation. Very popular in limestone and some shale formations.



2. Avoid drilling into water below (or gas above) hydrocarbons or perforating adjacent to water or gas. Either are thought to promote gas and water coning. Popular in formations containing relatively thin oil zones as compared with the underlying water zone. 3. Increase both the drainage area of the well in the reservoir and the lateral surface area of the well bore. The first .is thought to increase the cumulative hydrocarbon production, while the second enhances the hydrocarbon production rate. Popular in formations containing heavy oil. These holes may be thought of as drain holes in .some cases. 4. Intersect layered reservoirs at high dip angles. 5. Improve coal gas production (degasification). 6. Improve injection of water, gas, steam, chemical, and polymer into formations.



The counter proposal to the drilling of a horizontal· well is to drill a vertical well and hydraulically fracture the pay formation. This rarely accomplishes a purpose of a horizontal well, because hydraulic fracturing rarely if ever succeeds in intersecting many fractures in a naturally fractured formation; fractures usually intersect underlying water zones, and fractures filled with propants (sand) are not drain holes. The above purposes stipulate the requirements for the evaluation of a horizontal hole. 1. Hits all targets



2. Smooth turns and builds for promoting long lateral sections



HORIZONTAL DRILLING



373



MITCHELL Box 1492 Golden CO 80402



CHAPTER VIII



BOTTOM HOLE ASSEMBLIES DEFINITION OF BHA A bottom hole assembly (known as BRA) is a component of a drill string. A BHA resides in the drill string above the drill bit and below the drillpipe. The primary component of the BHA is the drill collar. The following figure shows the possible components of a BRA and their typical location within a BHA.



PURPOSE OF BHA The purposes of a BHA are as listed in the following. 1. protect the drillpipe in the drill string from excessive bending and



torsional loads, 2. control direction and inclination in directional holes, 3. drill more vertical holes, 4. drill straighter holes, 5. reduce severities of doglegs, keyseats, and ledges, 6. assure that casing can be run into a hole, 7. increase drill bit performance, 8. reduce rough drilling, (rig and drill string vibrations), 9. as a tool in fishing, testing, and workover operations, 10. not to place weight on the drill bit



TYPES OF BHA'S The "SLICK" BRA is composed only of drill collars. It is least expensive and perhaps carries the least risk in regard to fishing and recovery. The "PENDULUM" BHA is designed to drill holes more vertically and to drop inclination in inclined holes. Lubinski and Woods published tables and charts to locate the lowest most stabilizers in the BHA. Most BHA theories which were intended for vertical holes apply to holes wliich are inclined 20 degrees or less. The "PACKED" BRA is designed to drill straight holes and to reduce the severities of doglegs, keyseats, and ledges. It provides the highest assurance that casing can be run into a hole. The theory which supports the packedBHA was developed by Roch. A packed BHA can be expensive and perhaps carries the highest risk in regard to fishing and recovery. The "DIRECTIONAL" BRA is designed either to turn the hole to a chosen inclination and direction or to maintain a course selected for the hole. The directional BRA is based on the principles of levers and fulcrums.



BOTTOM HOLE ASSEMBLIES



427



MITCHELL Box 1492 Golden CO 80402



CHAPTER IX.



AIR DRILLING INTRODUCTION Air drilling utilizes air or gas as the borehole circulating fluid. Four categories of air drilling exist. These are straight air, mist, foam, and aerated mud. Straight air drilling requires only that air be compressed and circulated such that bit cuttings are lifted from the borehole. Mist drilling requires the addition of a foaming agent (surfactant) to the compressed air. Small volumes of water are lifted as droplets. The bit cuttings are wet; however, the· continuous fluid phase within the wellbore is air. Foam drilling requires the addition of a foaming agent and water or mud to the air. If water is used, the :·esulting circulating fluid is called foam and if mud is used it is' called stiff foam. Large volumes of water may be lifted (30-40 gph). The air appears as tightly compressed bubbles in an ascending liquid stream. In aerated water drilling, water is the primary circulating medium and air is added without a foaming agent. Thus, foam is not created and the continuous fluid phase is water. If mud replaces the water, it is called aerated mud drilling.



ADVANTAGES AND LIMITATIONS OF AIR/GAS The selection of air drilling systems in preference to normal mud is based on the feasibility of drilling the hole and, of course, economics. The primary advantages of straight air drilling are greatly increased penetration rates (2 to 10 times faster), more bit footage and fewer borehole drilling problems which lead to fishing operations. Water, gas and/or oil flow into the wellbore from porous zones limits the feasibility of straight air drilling. Compressor rental will increase "daily costs by 50 %. Mist drilling is usually selected to follow straight air drilling after a porous water zone is encountered. Generally, drilling rates and bit footage drop and the risk of fishing increases. Large water flows from porous zones usually require a conversion to mud drilling. Compressor costs increase slightly over straight air drilling and chemical costs may become critical. Foam drilling is a specialty system. Its primary advantages are attributable to its reduced head on formations near or at the bottom of the borehole and high cuttings lifting capacity. It is frequently used for drilling known lost circulation zones and pay zones. Alaska's operations have shown that near-gage holes can be drilled with foam through permafrost and frozen zones because of its low heat capacity and poor heat conductance. Foam disposal can be a problem. Aerated mud or water is popular in combating lost circulation zones and especially so if they occur in conjunction with prolific water flows. The problem is that overlying water zones require subnormal heads while lower zones require a more normal head. Disposal of excessive produced water can be a problem. AIR DRilliNG



467



MITCHEll Box 1492 Golden CO 80402



CHAPTER X



CEMENT ONE DOZEN CEMENTATION PROBLEMS There are a dozen major problems which may occur during primary cementations. The following is a list of those problems. 1. Poor displacement of the drilling mud, solids, and cuttings beds over the length of the hole that is being cemented. 2. Lost circulation during or after the cementation. 3. Bridges composed of cement filter cake. 4. Swapping out of drilling mud left below the pipe and cement circulated around the pipe (particularly bad in the setting of open plugs). 5. Flash setting of cement. 6. Shrinkage of cement. 7. Permeability after setting of the cement. 8. Gas migration (percolating gas) during the setting of the cement. 9. Micro-annulus from pressure and temperature within and of the pIpe. 10. Temperature strength retrogration of the cement. 11. Perforation of cement. 12. Cement settling in high angle holes". 13. Equipment, planning, and execution failures (people errors) and the quality of cement and additives.



SOLUTIONS TO A DOZEN PROBLEMS #1 PROBLEM: POOR DISPLACEMENT OF MUD



MECHANISM: The volumetric' fraction of the mud removed from the wellbore annulus by the cement slurry is called displacement efficiency. High displacement efficiencies increase the probability that the set cement will not contain channels of mud or that the cement will not have channeled through the mud. Satisfactory displacement efficiencies depend on many factors; however, the type of flow regime in which the cement slurry and the mud being displaced is flowing during displacement is dominant. SOLUTION: The recognized flow regimes are (1) plug, (2) laminar and, (3) turbulent. The dominant solution to poor mud displacement is cement hydraulics. Other aids are pipe rotation and reciprocation. Mobil Oil showed rotation speeds of 35 rpm are sufficient. Exxon showed 800/0 standoff with centralizers is sufficient with proper cement and hydraulics.



CEMENT



506



MITCHELL Box 1492 Golden CO 80402



CHAPTER XI



DRILL BIT SELECTION INTRODUCTION One of the more confusing aspects of oilwell drilling to the young and old a like is the numerous types of drill bits. The largest manufacturer of drill bits makes 34 types and 33 sizes (diameters) and many more on request. The International Association of Drilling Contractors (IADC) organization has a system of assigning a designation code to each bit type. The meaning of the codes are shown in the table. The primary short coming of the API coding system is caused by the fact that manufacturers' bits which on the surface may appear similar are very different in substance. The IADC category of bits and types (called bit codes) are 1. roller cone



FEATURES BIT CLASSIFICAnON FORM 01



CD



c::



.S



'C



~-g



ro "00



~8



~m



(f)



a:w



(f)



!l iii .c:



0 0 J-:



~



~



:E



FORMATIONS



Soft formations with low 1 compressive strength and high drillability Medium to med-hard 2 formations with high compressive strength Hard semi-abrasive and 3 abrasive formations



4



Soft formations with low compressive strength and high drillability



Soft formations with low 5 compressive strength



.!



-



Medium hard formations 6 with high compressive strenoth



.E



Hard semi-abrasive and 7 abrasive formations



iii ~



(1) U)



en



"0-



0-



(f)er:.



W



W



.£: ~ c:: ciS_ .2 t>



"0 C



>~ 1 2 3 4 1 2 3 4 1 2 3 4 1



c~



~(.) (5.~



So



1



OJo C en



OtO



o:e>



2



3



c::



~.§



;u



o e:> (f)CD



o to (f)C)



me:> (f)C'O



cr



g~



cr