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ARTIFICIAL LIFT METHODS COMPARISON TABLE



AL Methods Comparison Table Characteristic Production rate



Specific Less than 1000 B/D



Gas Lift The full range of production rates can be handled. An AOF production rate cannot be achieved with gas lift because as much drawdown as for an ESP cannot be achieved.



1000 to 10,000 B/D



Well depth



Greater than 10,000 B/D Less than 2500 ft



Not restricted by well depth. The benefit of gas lift will be larger with greater depth, as there is more fluid to ‘lighten’ to enable increased well productivity.



ESP The full range of production rates can be handled. When unconstrained an ESP can be designed to produce the full well potential to the surface (AOF), thus achieving higher flow rates than with gas lift.



Not restricted by well depth. The benefit of ESP will be larger with greater depth as there is more fluid head to overcome to enable increased well productivity.



2500 to 7500 ft Greater than 7500 ft



Casing size



4 ½ in.



Production tubing restricted to 2-3/8” tubing when installing side pocket mandrels. Packoff mandrels internal to the tubing can allow larger tubing size.



ESP restricted to a maximum diameter of 3.75” with a maximum flow rate of 2000 BPD (320 m3 /D).



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PCP



Rod Pump



Jet Pump



Rate is dependent on setting depth, the deeper the setting depth the lesser rates. Generally PCP is suitable for low rate wells.



Rate is dependent on setting depth. Feasible for low rates ( 65 degrees.



ESP restricted to a maximum diameter of 4.56” with a maximum flow rate of 5200 BPD (830 m3 /D).



The majority of pumps will fit into this casing with OD=4.5”. Up to 4000 b/d at 3000 feet.



ESP restricted to a maximum diameter of 5.40” with a maximum flow rate of 12000 BPD (1900 m 3 /D).



No detriment to performance with pump inside larger casing. Some larger models available with OD=5 -3/8”. Up to 3200 b/d at 5000 feet. All pumps will fit this casing.



Well suited to horizontal wells unless the tubing is large preventing produced fluid mixing with lift gas. Retrieval of gas lift valves from side pocket mandrels can be difficult when the deviation angle > 65 degrees. Gas lift causes no constraint.



Well suited to horizontal wells, however size and running of ESP limited by well trajectory. A straight section of casing is required at ESP depth.



ESP restricted by horsepower to a maximum flow rate of 90,000 BPD (14,400 m 3 /D).



Rod Pump



Jet Pump



of downhole pump design in small diameter casing.



Well suited to vertical wells.



No constraint – typical installation with top drive and rods.



Well suited to vertical wells.



Well suited for vertical completions.



Well suited to deviated wells, however size and running of ESP limited by well trajectory. A straight section of casing is required at ESP depth.



Can deal with deviation however rod wear is a reliability constraint. Rod guides are used to reduce friction on rods. REDA PC has application where the well is deviated and the reduced risk of failure due to rods is required. Pumps have been installed in horizontal section but same remarks for deviated well are applicable.



Not highly recommended. Slanted and crooked wells present a friction problem. There are increased load and wear problems in high angle deviated holes (>70 o).



Well suited for deviated completions.



Not recommended.



Could suit for horizontal completions. However, due to well trajectory, slickline work to pull nozzle could be a problem.



No constraint



No constraint.



No constraint.



Pump length dependent. Typical pump length = 35 feet which is relatively short and easy to deploy through doglegs.



No big constraint. Centralizer could be utilized.



No contraint.



ESP can be deployed without problem. ESP system may be limited as ideal system cannot be readily deployed through this dogleg.



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ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Gas Lift



Greater than 10° per 100’



Temperature



PCP



Rod Pump o



Jet Pump



Not recommended.



Same as above



Zero to 90 landed pump. Some success is accomplished in pumping 15 o /100 ft using rod guides.



Recommended for all temperatures



Standard ESP design will handle this temperature.



Can lift high temperature and viscous oils.



Above current limit



Operating temperature range from 0 to 550 o F.



Temperature limitation is excellent. It is possible to operate from 0 to 500+o F.



Barriers



3 barriers can be achieved



Medium range equipment required. Higher temperatures require specialised ESP designed equipment, which have been shown to operate at 550 F. Note that the motor temperature is significantly higher than the bottom hole temperature. Extremely high temperatures will cause a short run life. 3 barriers can be achieved



Standard PCP design with suitable elastomers will handle this temperature. Above current limit



Restricted by rod strings. Surface wellhead valve – one barrier.



3 barriers can be achieved.



Hydrocarbon inventory



Gas lift entails a large inventory of hydrocarbon gas in the annulus or tubing that upon catastrophic failure of wellhead will be vented to the atmosphere. Solution can be to install an annular SSV to limit the inventory.



Restricted by rod strings. Surface wellhead valve – one barrier. Use of REDA PC would allow deployment of SCSSV. No hydrocarbon inventory and the extra facility of shutting off produced fluid flow by stopping the pump.



No hydrocarbon inventory and the extra facility of shutting off produced fluid flow by stopping the pump.



During operation, large amount of crude is being stored in vessels and surface lines. If rupture takes place and create a major catastrophic at surface, the well needs be shut-in to bleed off.



Less than 250°F 250 to 350°F Greater than 350°F



Safety



ESP



No hydrocarbon inventory and the extra facility of shutting off produced fluid flow by stopping the pump.



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Applicable for slanted and crooked wells. Short jet pumps can pass through doglegs up to 24-deg/100 ft in 2 in. nominal tubing. Zero to 90 Degrees pump placement. Guideline as below: Piston Hydraulic lift:



350 psig to 5,000 ft with low GLR. Typical design target is 25% submergence. Cannot deliver fluids to surface.



Good drawdown but cannot completely deplete a well.



For gassy reservoir. Rod pump handling is fair to good.



Not recommended. Cavitation in jet pump likely.



Rod pump can be effective in



Jet pump can be effective in



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Reservoir access



Primary Secondary waterflood



Tertiary



Pressure support



ESP



producing a well that cones water. Gas lift results in simple completions that allow ready access to the reservoir for surveillance and remedial work.



producing a well that cones water. Downhole ESP equipment restricts access. A logging bypass can be installed but this complicates the equipment and downsizes the ESP. Remedial work requires a full workover. Coil Tubing deployed ESP can solve some reservoir access problems, but pulling the ESP would still be required. Not recommended for unstable flow.



Gas lift is able to handle all types of flow regimes be they stable or unstable.



Flow Stability



Recovery



Gas Lift



Yes



No



PCP



Recommended Recommended, however high water cut reduces the ability to move large fluid volumes. Can be used with tertiary recovery methods.



Recommended Recommended



Well suited, however increasing water cut reduces the ability to move large fluid volumes. Recommended as the flexibility of gas lift allows one installation to deal with falling pressure and production rates.



Recommended as an ESP is able to move the same fluid volume no matter what water cut. Not recommended when there is significant pressure drop – the range of production rates that a particular ESP design can handle is limited. Hence the reservoir condition rate of change would define the ESP change out frequency rather than ESP mechanical run life. Variable frequency drives (VFD) allow some operational flexibility on matching the production rate to the ESP design.



Can be used with tertiary recovery methods.



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Rod Pump



Jet Pump



producing a well that cones water. No reservoir access.



producing a well that cones water. No reservoir access. Cannot run any type of surveillance log.



producing a well that cones water. Good. If set in a sliding sleeve, the jet pump can be retrieved by wire line allowing access to reservoir.



Not recommended. Need continuous fluid through pump. Use of downhole monitoring to control surface VFD could be used. Recommended Recommended



Not recommended for unstable flow.



Continuous and smooth flow of produced fluids.



Recommended Recommended



Recommended Recommended



Steam flood will cause a problem, as temperature will be increased. Recommended



Not recommended when there is significant pressure drop – the range of production rates that a particular PCP design can handle is limited. Hence the reservoir condition rate of change would define the PCP change out frequency rather than PCP mechanical run life. Variable frequency drives (VFD) allow some operational flexibility on matching the production rate to the PCP design.



Can be used with tertiary recovery methods. Recommended



If there is no pressure support from the reservoir, production rate will decline and the well will be “pumped-off”.



Recommended, as jet pump system is independent of water cut percentage producing from a well. Not recommended when there is significant pressure drop in the reservoir – the range of production rates that a particular jet pump design can handle is limited. A new jet pump design needs to be in placed to get optimum lift for the well.



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Low



Recommended.



Recommended for the full range of water cut. The ESP is largely insensitive to increasing water cut.



Moderate



Reduced efficiency due to heavier column of fluid to lighten. Reduced efficiency due to heavier column of fluid to lighten. May not be able to lift well if reservoir pressure is low. Recommended



Less than 100 cp gas free viscosity at reservoir temperature 100 to 500 cp gas free viscosity at reservoir temperature Greater than 500 cp gas free viscosity at reservoir temperature



Corrosive fluid



PCP



No limitat ions. Preferable > 12 o API.



High



Fluid viscosity



ESP



No limitations. Preferable > 15 o API.



Oil Gravity



Water Cut



Gas Lift



Rod Pump o



Jet Pump o



Not used for oil with gravity greater than 40 degrees API due to high aromatic content (C6 to C9 should be under 20%) that will deteriorate elastomers. Preferable < 30 o API. Recommended



> 8 API.



> 8 to 45 API.



Recommended



Recommended



Recommended



Recommended



Recommended



Recommended



Recommended



Recommended Up to 100%



Recommended



Recommended



Recommended



Recommended



Recommended



Efficiency of ESP will be reduced.



Recommended. Pump efficiency will increase as viscosity increases.



Recommended



Has been used with success up to 1000 cp but little case history for very high viscosity.



Not recommended. Pump efficiency is reduced, motors cool poorly in the high viscous fluid, more power is required to pump high viscous fluid and emulsions form. A mixture of ESP and progressive cavity pump technology is a potential alternative.



Recommended for all high viscosity crude. Up to 80,000 cp.



Good for < 200 cp fluids and low rate. Rod fall problem for high rates. Higher rates may require diluents to lower viscosity. Not recommended, as pump efficiency will reduce.



Recommended. Compatibility of metallurgy and elastomers with the total completion is only required.



Run life will be shortened in a more aggressive environment. Special metallurgy and elastomers will be required leading to more costly equipment.



Run life will be shortened in a more aggressive environment. Design with rotor in stainless steel and matched elastomers. Rod string and tubing is at risk as typically not special



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Using corrosion-resistant materials in the construction of subsurface pumps.



Mixture of power and producing fluid is not a major issue in Jet pump. The system is capable of handling high-viscosity fluid. Production with up to 800 cp possible. Oil power fluid in the range of >24 oAPI and 50% free gas. If the gas anchor or natural separation is used and free gas is venting, the volumetric efficiency can be significantly improved. Not recommended



Target design is less than 1000 GLR.



Not recommended, as the high bubble point will limit the maximum drawdown in the well due to the detrimental effects of free gas in the pump. Recommended. The bubble point pressure is low hence the FBHP can be low allowing more production without the affects of free gas in the pump region.



Not highly recommended.



Not recommended. Gas above 2000 SCF/STB substantially reduces efficiency but helps lift. Vent free gas if possible. The producing of free gas through the pump causes reduction in ability to handle liquids. Not recommended.



Recommended.



Recommended.



Recommended. PCP handles solids easily.



High solids and sand production is troublesome for low oil viscosity (200 cp) cases. May be able to handle up to 0.1% sand with special pumps.



Solids/sand handling ability is fair to poor. Jet pumps are operating with 3% sand in produced fluid. Power fluid to jet pump can tolerate 200 ppm of 25µ particle size. Fresh water treatment for salt



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Gas Lift



10 to 100 ppm



Scale



Scale can form close to the operating gas lift valve due to the pressure drop at that location. This may lead to blockage of the gas lift valves and an inability to be able to retrieve them.



Paraffin



Paraffin may deposit near an operating gas lift valve due to temperature and pressure drop. This may lead to blockage of the gas lift valves and an inability to be able to retrieve them Introduction of lift gas into the produced fluid stream may increase the risk of asphaltene deposits. Production chemistry analysis for individual fields will determine whether this is likely to occur. Recommended when any treatment is required. These treatments have little to no effect on a gas lifted system.



Asphaltene



Treatment



Scale inhibitor



PCP



ESP may be operated under these conditions but harder surface coatings are required. Not recommended due to friction and wear on ESP equipment.



Greater than 100 ppm



Contaminants



ESP



If the well is prone to scale, paraffin or asphaltenes deposit then it is likely to occur in the pump area (large pressure drop). This will lead to pump inefficiency, increased wear & tear and eventually failure. Chemical treatment is required to prevent formation of these contaminants.



Materials design will need to be modified to ensure continued service of the ESP after treatment.



Corrosion inhibitor



Rod Pump



Recommended.



build-up possible.



Recommended. Typically can handle up to 7-8% by volume. Design of elastomers for abrasion is required. Typically not a constraint but may need to be reviewed if well has a high scaling tendency.



Scale could build up at intake and nozzle over time but can be treated.



Not a problem due to the nature of PCP however efficiency will be reduced.



Susceptible to paraffin problems. Hot water/oil treating and/or uses of scrapers possible, but they increase operating problems and costs.



Does not increase deposition and will produce asphaltene to surface as a solid.



Can be treated.



Elastomer compatibility is a constraint so needs to be reviewed in detail for design.



Corrosion and scale treatments easy to perform. Good batch treating inhibitor down annulus used frequently for both corrosion and scale control. Corrosion handling good to excellent.



Solvent



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Jet Pump



Can be treated. Paraffin handling capability is good/excellent. Circulate heat to downhole pump to minimize build up. Mechanical cutting and inhibition possible. Difficult to control.



Corrosion/scale ability is good and sometimes excellent. Inhibitor with power fluid mixes with produced fluid at entry of jet pump throat. Batch treat down annulus feasible. Corrosion handling good to excellent. Can be surfaced at a predetermined schedule.



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Gas Lift



ESP



PCP



Acid Location



Ensure cleanout of well prior to re-installation. Recommended



Rod Pump



Onshore



Recommended



Recommended



Offshore platform



Excellent and recommended.



Excellent and recommended.



Good and recommended. Safety barriers may be a const raint.



Poor and not recommended. Must design for unit size, weight, and pulling unit space.



Subsea



Delivery of fluids under a gas lift scenario through a long sub sea delivery system will be significantly reduced. The gravity and friction of lengthy pipelines cannot be fully overcome by a gas lifted system. As the step out from the tie in delivery point is increased the efficiency of gas lift decreases. Running a gas lift system will include a flaring system, hence affecting the environment when the compressor is ‘blown down’.



Recommended. The ESP can be designed to overcome the head produced by the subsea delivery system. As step out from the tie in delivery point increases, ESP efficiency decreases, however an ESP is able to handle larger step outs than gas lift before zero flow occurs.



Not recommended except as REDA PC. Rate will not achieve benefits.



Not Recommended.



Recommended. The ESP when running has little potential impact on the environment.



Recommended. Leakage from stuffing box for rod only constraint – polished rod through wellhead.



Stuffing box leakage may be messy and a potential hazard. (Anti-pollution stuffing boxes are available.)



Sensitive environment



Recommended.



Fair in term of noise level. Moderately high for urban areas.



Number of Wells



Single



1 to 20



Typically cost of providing compression for a single well gas lift development is too high to be able to justify. As the number of wells increases the cost of the compression facilities becomes more economic on a well-bywell basis.



Recommended. ESP can be installed for a single well with standalone power generation and control. Recommended. Costs of power equipment will be reduced and rationalised as the number of wells completed increases.



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Recommended.



Recommended.



Recommended.



Recommended.



Jet Pump



Onshore applications are common. Good to excellent. Offshore applications are common. Produced water or seawater may be used as power fluid with well site type system or power fluid separation before production treating system. Not recommended due to intervention requirments and power fluid pump to remote location.



Power water (fresh, produced, or sea water) is acceptable. However, there is concern in sensitive areas if oil is used as power fluid , because of the high-pressure injection lines. Low in noise level. Well-site power-fluid units can be sound proofed. Due to surface size, operations are drawbacks in populated areas. Single wells are the most common. Multiple wells operating from one single surface hydraulic package greatly reduces lift cost.



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific Greater than 20



Electrical Power



Gas source



Yes



No



Facilities footprint



Start up



Well intervention



Gas Lift Recommended. Cost benefit for this number of wells justifies high costs for installation of compression. Not required.



Recommended. If a gas source is readily available either from produced gas, import gas or a gas well then gas lift is a viable artificial lift method. Not recommended, as the cost of obtaining a gas source will be large. Large amount of space is required to install a compression system. For areas where space is at a premium this can be a costly issue.



Gas lift is not recommended if after a shut down gas is not easily available. Gas can be sourced from: • Produced gas from naturally flowing well or artificially lifted by non gas lift method • A flowing gas well • Importing gas from an external source e.g. Pipeline For gas lift valve changeouts slick line intervention > 5 years. For subsea wells may not be required for life of well. For



ESP



PCP



Rod Pump



Jet Pump



Recommended.



Recommended.



Recommended.



A source of electric power is needed. This can be a tie in to an existing facility, a tie in to a power grid or independent power generation. Does not impact ESP solution.



Gas motor can be used. Less voltage required than ESP hence lower operating cost.



Can use electricity as power source. Prime mover flexibility is good: either engines or motors can be used easily (motors more reliable and flexible). Gas engines could be used in locations with no electricity.



Prime mover can be an electric motor. A diesel or gas engine can be used where electricity is not available.



Does not impact ESP solution.



Does not impact PCP solution.



Does not impact RP solution.



Does not impact JP solution.



Facilities often have power generation already installed hence the addition of power for ESP does not have as large an impact as for gas compression.



Small footprint. Facilities often have power generation already installed hence the addition of power for PCP does not have as large an impact as for gas compression.



Small footprint on surface. Facilities often have power generation already installed; hence the addition of power for a rod pump unit does not have as large an impact as for gas compression.



Once power is available to the facility ESP systems will be able to be run.



Once power is available to the facility PCP systems will be able to be run.



Once power is available to the facility, rod pump systems will be able to be run.



Large amount of surface spacing is required. Surface unit can be mounted on one skid or two skids for a dualvessel power fluid cleaning unit. Two skids for a 200 HP unit with engine prime mover may have a footprint of approximately 8 feet by 18 feet each. Requires some fluid (water or oil) to fill the vessels as power fluid prior to start up.



Run life of ESP determines intervention frequency. Change out of total completion required for ESP failure.



Run life of PCP determines intervention frequency. Change out of total completion required for ESP failure. Average run life



Workover or pulling rig. Run time efficiency is greater than 90% if good operating practices are followed and if corrosion,



Hydraulically removed or wirelined. A “free” jet pump can be circulated to the surface without pulling the



Does not impact PCP solution.



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Produced gas from the well can be used to power a gas engine prime mover.



ARTIFICIAL LIFT METHODS COMPARISON TABLE



Characteristic



Specific



Gas Lift



ESP



PCP



remedial well work as required with the ability to perform through tubing workovers.



Average run life approximately two years. Remedial work will require completion to be removed



wax, asphaltenes, solids, etc… are controlled.



tubing or it can be retrieved by wire line. Must avoid operating in cavitation range of jet pumps throat; related to pump intake pressure.



CAPEX



High for compression and gas distribution system



High for power generation and cabling



approximately one to one and a half years. Remedial work will require completion to be removed. Total change out can be avoided by using wireline retrievable with REDA PC or put rotor and stator on rod string so doesn’t have to pull tubing. Moderate cost for facilities and down hole equipment.



Capital costs are low to moderate. Cost increase with depth and larger surface units.



OPEX



Low. Gas lift systems have a very low OPEX due to the downhole reliability.



Moderate to high. Costly interventions are required to change out conventional ESP completions, but productivity and improved run life can offset these costs.



Moderate cost for equipment but high intervention frequency.



Operating costs are very low for shallow to medium depth (< 7500 ft) and low production (< 400 BFPD). Units easily changed to other wells (i.e. reuse) with minimum cost.



Capital costs are competitive with sucker-rod pumps. Cost increases with higher horsepower. Wellhead equipment has low profile. Requires surface treating and high pressure pumping equipment. High power cost owing to horsepower requirement to pump power fluid. Typical jet pump efficiency is 30% thus power fluid at 2-3 times the produced fluid rate is required. No moving parts in pump; simple repair procedures. Low pump maintenance cost typical with properly sized throat and nozzle.



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Rod Pump



Jet Pump