Performance Evaluations of the Different Sucker Rod Artificial Lift Systems

Transcription

1 SPE MS Performance Evaluations of the Different Sucker Rod Artificial Lift Systems M. Kennedy Dave and M. Ghareeb Mustafa, SSI Lift Copyright 2017, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Symposium: Production Enhancement and Cost Optimisation held in Kuala Lumpur, Malaysia, 7-8 November This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The majority of oil wells operated throughout the world requires some form of artificial lift during their life cycle. Wells lifted by reciprocating sucker rod pumping systems represent almost more than 70 % of the total artificially lifted oil wells worldwide. As consequence of previous and current global crisis, the pressure on the operators is to maximizing production and net profit out in a very safe and environmentally controlled manner. The primary challenge is to select the suitable system capable to achieve these goals over the life cycle of the well. For years, operators have been looking for reliable, flexible and intelligent lifting systems to improve their operating costs, reservoir recovery factor by maximizing well production and filed safety. There are several sucker rod-pumping systems applied all over the world. Each has its different advantages and disadvantage. Selecting the right system technology requires detailed analysis, including well, fluids, reservoir and location. This study will present detailed comparisons between the different systems in the area of production, depth, downhole failures, power saving, safety related to system operations. The comparison will be between the conventional beam, enhanced geometry beam, linear vertical mechanical Long Stroke pumping units and long stroke Wellhead Mounted Hydraulic pumping units systems. This study was undertaken using advanced predictive methods. The results compared with actual field applications from Canada, USA, Latin America and Middle East. The latest technology in sucker rod pumping systems regarding the system s capabilities as production, depth, optimization, power consumption and control considered in this study. Introduction Artificial lift is need in wells when there is insufficient energy (depleted and/or naturally flowing wells) in the reservoir to lift the desired production rate of the well fluids to the surface with wellhead pressure capable to displace the produced fluid to the production facilities. Generally, this is achieve by the use of a device inside the wellbore and/or by decreasing the weight of the hydrostatic fluid column by injecting gas into the liquid some distance down the wellbore. There are several types of artificial Lift systems using to move the production fluids to the surface. Reciprocating Sucker Rod Pumping (SRP)

2 2 SPE MS Electric Submersible Pumps (ESP) Progressive Cavity Pumps (PCP) Gas Lift (GL) Plunger Lift (PL) Hydraulic jet pumps (JP) The earliest documented reciprocating walking beam artificial lift system described in the Egyptian historical writing dated 476 AD2 and called Shadof as shown in Figure 1. It was limited to lift low volume of water from shallow depth. Figure 1 First beam unit system (Shadof) With the time, the new discover oil reservoirs (oil fields) became harder in production as fluid type, production rate, reservoir pressures, well depth, hole characterizations etc. This push the manufactures to present and develop different forms of surface and subsurface equipment in order to produce these reservoirs. The mechanism introduced to oil industries was not different in principle than Shadof. It is name Beam Pumping units (pump jacks or surface pumping units). Different geometries and configurations introduced as shown by Figures (2a) and (2b). The beam unit is used to stroke the bottom hole pump up and down. This is accomplished by converting rotary motion to reciprocating vertical motion. Rotary power is supplied to a gear reduce by a prime mover. The gear reducer uses a series of gears to convert the high-speed power supplied by the prime mover to low speed power. (Usually a ratio of approximately 30 to 1 on a double reduction unit). The gear reducer turns the cranks and the cranks lift the pitman arms up and down (rotary to reciprocating). The pitman arms move the walking beam up and down consequently the horses head on the opposite end of the walking beam has to go up and down. This action causes the bridle cable to move the carrier bar up and down which in turn moves the sucker rod string up and down and consequently the traveling valve that connect to plunger.

3 SPE MS 3 Figure 2a Conventional Beam Pumping Units Figure 2b Enhanced Geometry Beam Pumping Units These traditional beam pumps has not seen much evolution or change in over 100 years. These type of pumping units are limited in the capabilities to produce high fluid volume and improve the well performance in difficult wells (wellbore and/or fluids). Some of these challenges are: The mechanical wear between rod and tubing especially in deviated and/or crooked holes which present a friction problem Inefficient pumping in gassy wells Depth limited, primarily because of rods and surface unit capabilities. Obtrusive in urban locations. Safety hazards. Pumping units have large and heavy rotating parts. To overcome some of these challenges the manufactured introduced in the late 1980s a mechanical longstroke pumping unit (Figure 3). It offered many advantages over traditional beam pumping units. This vertical mechanical system is lacking of the flexibility of changing stroke lengths where it is limited to three of four choices.

4 4 SPE MS Figure 3 mechanical long-stroke pumping unit Today s due to the level of the oil prices, well operators require more control on well operation and economics than the beams and mechanical long stroke units can do. To address this, industry has introduced intelligent hydraulic skid mounted long stroke pumping units Figure 4. They offer fully flexible longer stroke lengths which allowing operators to make the same or more fluid with less number of strokes. This result in less wear and tear on the sucker rods, tubing and the bottom-hole pump. Reduced wear will reduced the frequent well interventions, and increase mean time between failures (MTBF). This will lead to increase well production and reducing lifting cost and safety hazard. In addition, this new type of hydraulics units are able to overcome the rod fall (carrier bar separation) issues. Figure 4 Long Stroke Hydraulic skid mounted unit Systems Evaluation for Well Depth and Production Capabilities Many factors must be consider when evaluate the performance of the applied lift system for a particular well. One of the main evaluation criteria is the range of depth and production rate where particular lift types can function. The ability of a sucker rod pumping system to produce a fluid is constrained by (1) the stroke length, (2) the plunger diameter of the bottom-hole pump, (3) the strength of the sucker rods, (4) unit capacity and

5 SPE MS 5 geometry and (5) the rod free fall from a given well. For any given pumping unit the critical pump speed is controlled by two main variables, (1) stroke length, and (2) the well forces, such as friction, buoyancy, etc., that retard rod fall (Byrd, 1968). Several field studies and simulations done to predict the behavior of the rod lift system to produce a practicality high volumes production. The majority of these studies ignored rod buckling tendency and almost most of them when studied the system capabilities as production and depth not considered the effect of wells and fluids problems. It will be cover in this study. A simulation study made by using one of program using for sucker rod pumping system design (SROD) to compare the performance of four of common using long stroke surface pumping units (conventional beam enhanced geometry beam, mechanical long stroke and hydraulic skid mounted long). This study done by consider three different cases for well depths and productions. Table 1 presented the criteria used in the designs. Table 1 Criteria used in the design. Depth Production Pump intake Pressure psi 100 Surface wellhead Pressure psi 200 Tubing Size inch, 3.5 Water Cut % 50 Oil Gravity API 30 Water Gravity 1.05 A number of general assumptions were applied in making these simulations. In all cases the wells considered vertical and tubing was anchored, thus no tubing stretch. The output results of the simulation for the three cases are shown in Tables 2, 3 and 4 for three depths 5000 ft, 8000 ft and 11,000 ft respectively. Analyses of the three tables indicates that as stroke length increases, the required pumping speed SPM (stroke per minutes) to produce the same volume of fluid decreased. This lead to decrease PPRL (peak polished rod load) while MPRL (minimum polished rod load) increases due to dynamic effects. This will increase the well performance and reduces well intervention due to decreasing buckling tendencies, decreasing side & drag loads, decreasing rod loading and decreasing the load range (PPRL MPRL). Fewer cycles mean less rods, tubing, and pump wear will be seen Lower losses of stroke as a percentage of the total stroke, making the system more efficient. Table 2 simulation results for well producing 1000 BFPD form 5000 ft. C 1280 D M 912 D RF SSI Power Required (hp) Surface Max Load (lbs) Surface Min Load (lbs) Average Pumping Speed (SPM) Polished Rod Horse Power (hp) Computed Surface Stroke (in) In-balance Max Torque (m in-lbs) NA Pump Diameter (in) 2.75

6 6 SPE MS C 1280 D M 912 D RF SSI Net Pump Stroke, inches Net bpd at 100% pump eff 1000 Rod Loading % Service Factor 0.9 Rod Type UHS Rod String 86 Table 3 simulation results for well producing 700 BFPD form 8000 ft. C 1280 D M 912 D RF SSI Power Required (hp) Surface Max Load (lbs) Surface Min Load (lbs) Average Pumping Speed (SPM) Polished Rod Horse Power (hp) Computed Surface Stroke (in) In-balance Max Torque (m in-lbs) Pump Diameter (in) 2.25 Net Pump Stroke, inches Net bpd at 100% pump eff 700 Rod Loading % Service Factor 0.9 Rod Type UHS Rod String 86 Table 4 simulation results for well producing 300 BFPD form ft. C 1280 D M 912 D RF SSI Power Required (hp) Surface Max Load (lbs) Surface Min Load (lbs) Average Pumping Speed (SPM) Polished Rod Horse Power (hp) Computed Surface Stroke (in) In-balance Max Torque (m in-lbs) Pump Diameter (in) 1.5 Net Pump Stroke, inches Net bpd at 100% pump eff 300 Rod Loading % Service Factor 0.9 Rod Type UHS Rod String 86

7 SPE MS 7 Systems Evaluation by Operation Modes and Related Downhole Failures Sucker rod operation modes are usually designed based on well production and well & fluids conditions. Three main parameters are mainly controlled well production rate and well performance. These parameters are subsurface pump, stroke length and pumping speed. The stroke length and pumping speed are generated by the surface pumping unit. Therefore selecting the right surface pumping unit can have great impact in the system performance and controlling the equipment failures frequency. For a particular production rate and set of well conditions there are many combinations of stroke lengths, strokes per minute and plunger diameter. Most failures associated with the reciprocating sucker rod pumped wells can be attributed to one of downhole components (subsurface pump, sucker rod string, tubing string etc.). Failure of these components will required servicing rig to pull and change out one or more of these parts. The rate of the failure frequency (Numbers of component failures/ well, per year) will have direct impact in the well performance and economics. Effectively manage the failures rate to generate the highest revenue possible will required carefully select the most efficient running parameters in order to reduce well failure frequency rate. Using the simulation data presented by tables 2, 3 and 4, the type of the surface unit and its operational modes are cleared in its effect in the equipment running lives and system performance for the following common problems: Rod buckling: It is one of the main problem in rod-pumped wells especially deviated well. It happens during the downstroke. The rod buckles and contact against tubing. It cause tubing ware and leaks. It can also cause rod parts. The main reasons for rod buckling are: Downhole friction, especially in a deviated well due to larger drag friction. Pumping speed. Increasing pumping speed especially in the downstroke can cause rod compression due to the rod dynamic. Tension force becomes a compression at free end of pump. It happens both in vertical and deviated wells. Pump-off condition and /or under-balance condition may also aggravate buckling. Some unit geometry may also aggravate buckling tendency at fluid pound condition. Most cases of rod buckling happens at any combination of above. Comparing the performance of Beam, Hydraulic Skid mounted long stroke and mechanical long stroke units along with their features and controller capabilities in running wells with rod buckling problems, indicated that the longer the stroke the better the performance in handling this type of wells. This is mainly due to several reasons. The longer stroke especially ultra-long stroke length units allow to use a smaller subsurface pump size to handle the same production. Use smaller pump will reduce the fluid loads consequently reduce the side/drag loads between rods and tubing. Long stroke with smaller pump size and slow speed will reduce the dynamic caused rod buckling and peak polished rod load. The buckling tendency overcome to high degree when using hydraulic units with the integrated intelligent control system. Adjustable accelerations and decelerations at the top and the bottom of the stroke combined with variable speed control on the up and down stroke. Fluid Pound: As experienced in a pumping oil well, fluid pound is one of the most common operational problems. It is caused when the subsurface pump not completely filled with liquid on the upstroke. As the downstroke begins, the entire fluid and rod string load moves down through a void until the plunger hits the fluid level in the pump barrel which transmits a shock wave through the pumping system (Figure 5). This shock wave causes damages entire parts of the pumping system. This problem occurs when the downhole pump operated at a rate exceeds the production rate of the formation. It is usually the main cause of fatigue failures of the surface pumping unit

8 8 SPE MS (structure, gear teeth, bearings and unit base), rod string. It accelerate subsurface pump components (valves, valve rod and barrel) failures. Also fluid pound accelerates wear of the tubing due to rod buckling. Performance evaluation of the different surface pumping units in running wells suffered from pounding fluids done based on the units concept of operation and its flexibility in adapting the unit s running parameters (speeds and stroke length). Followings are the main observations: Conventional and enhanced geometry beam units which have fixed speed for up and downstrokes, the performance were found to be very low and the reported failure rates were very high. Initially the operators improve the situation by used well timers and pump off controllers. The use of timers or pump off controllers lead in some wells to reduce the well production. This is because in the period of down time, the well production will decrease with increasing the fluid level (well will be under build-up condition). Also, since it is primarily used as an on/off type control, the system will transfer from static to dynamic several time per hours. This will accelerate the motor, surface unit, rods failures. The situations was notices worst in the cases when using the enhanced geometry units. This is because this units featured with faster downstroke speed compared with the upstroke. The fasted down stroke increase the shock wave what the plunger hit the fluid inside the pump barrel. Also, on and off is not preferred for well produce with certain amount of sand. San can fall back on top of the plunger if the off periods. Linear vertical mechanical Long Stroke pumping units. This unit proved to be much better than Beam type units. Manly due to the feature of the long stroke and slow pumping speed. This allow for more time for (Fill Time) the fluid to inflow to the pump during the upstroke. When unit is equipment with variable frequency drive, pumping speed can be slow down. The drawdown of such type of unit is the availability of the stroke lengths. It is limited to 3 to 4 lengths. This will reduce the chance to reduce the unit running parameters in order to match well productivity. Therefore chance of fluid pound problems is exist. Hydraulic skid mounted Long Stroke Pumping Units. This type of units shows the best performance in running wells with fluid pounding problem. This is mainly found to be due to the different features these units have. Where with very simple adjustments while the unit is running, an operator can optimize the system to match pumping conditions to well productivity. The stroke length can be made from one inch to the maximum allowable stroke with one inch increments. For example, a unit equipped with 360 inches, the available stroke lengths are 1, 2, 3, 4.358, 359,360 inches. This wide range of stroke lengths with the availability to speed up or down the units, operator can adjust very closely the unit running parameters to match well productivity and fluid pound can almost eliminated. It also featured with independent Up and down stroke speed. Speed can be control by slowing down the up stroke period in order to allow for more time for (Fill Time) the fluid to inflow to the pump during the upstroke. The longer the time interval of the upstroke, the longer the fill time to charge the barrel, and the greater the amount of fluid permitted to inflow during the productive cycle; hence, increased production. Moreover to avoid the shock force resulting from fluid pounding condition, this type of system is featured with a very smart automation system which can lead to almost eliminate the bad effect of the fluid pound in the entire system. It provides Eight Independent Speeds for Up and Down Stroke plus Independent Acceleration and deceleration for Up and Down Stroke. The unit can be adjusted to slow down almost near to zero speed in the downstroke before it hits the fluid level inside the pump. This will allow the plunger to pass the fluid without any shock load and by that, the fluid pound will eliminated.

9 SPE MS 9 Figure 5 Fluid Pound Safety related to system operations Sucker rod pumped well are running with large equipment running 24/7. Therefore when we compare the different surface unit s safety hazards, we need to consider all the type of operations where the times of particular danger can happen. This can occur mainly during: The erection, Stroke change, Counterbalance change, General unit maintenance, Well servicing and While taking dynamometer card reading. A review of recent and historic incidents show that Beam type units related worker fatalities is the worst among the other type of units. This is because Pumping units have large and heavy rotating parts. Even a temporarily stationary pumping units has components which can start moving from the effect of gravity. Comparing with the long stroke vertical units where almost all moving parts enclosed within the tower and away from personnel, very few incidents reported. The Hydraulic skid mounted computerized units recorded the safest units. Where No crane required for work-over activities a tracking system for sliding pumping unit back and forward for well workover without dismantle the unit is using. Therefore less injuries exposure observed. Also all the required operations for changing stroke length, pumping speed and balancing the units found to be more safer where all can be done without stopping or access the units. All these operations done from the power skid. Case Histories Case Study 1: San Ardo, California oil producer had a need to increase production beyond that which was possible with a beam pump, but wanted to avoid the additional costs of operating an ESP, while also reducing maintenance costs resulting from frequent rod separations.

10 10 SPE MS To achieve the goal the producer installed late in 2008 four Skid mounted long stroke pumping units with 100 hp power units. Immediately upon startup, the long stroke units have resulted in a more than 25% increase in production over the beam pump's production of less than 2,000 BFPD to over 2500 BFPD on each well. This production increase has been achieved while decreasing strokes per minute by 60%, from 10 SPM to 4 SPM. This has resulted in substantially lower failures frequency for downhole parts (rod, tubing and downhole pump. Installation & Purchase Payback in 6 Weeks; Over $1 Million Increase in Annual Cash Flow per Well due to the this increased in production and reducing in well interventions costs Case Study 2: Major International Producer Wyoming, USA have wells had severe side loading and high frequent well services. Being June 2013 they installed four ultra-long stroke hydraulic SSI units. This in order to evaluate the performance of using the fully control long stroke hydraulic units with the target of reducing rod cycles (failures) while l maximizing liquid production. No tubing or rod failures up to date. Case Study 3: A Wasson Clearfork Team evaluated the performance of Hydraulic ling stroke skid mounted units on deviated wells. The results was concluded as follows: Increased Production - In one case, a Conventional 912 pumping at 7.9 SPM with a 2.25" BHP producing 420 BFPD was changed to DynaPump Model 9 pumping at 4.3 SPM with a 2.25" BHP and ending up producing 505 BFPD. This was a 20% increase without changing the size of the BHP. In most cases, the BHP was increased to the next larger API pump size and production increased at least proportionally, although in a few cases the well was subsequently pumped off with the larger pump. In at least one case, the change to the DynaPump (SSI Lift)resulted in an increase in the production of oil by 25 BPD. Less Down Time and Rig Cost Certain wells have relatively high well maintenance cost related to rod parts, tubing wear out, and BHP failures. Operator has even experienced some wells using submersible pumps that have a high rate of replacement. Of course any time a well must be pulled to complete repairs there are two negative operating factors that come into play: one is the cost of the rig crew plus the cost of the replacement parts, and the other factor is the lost production revenue while the pump is out of service. One common characteristic of the wells that have very high well maintenance costs is that they have a severe deviation profile. In these cases, beam pumps running very fast experience a high rate of parted rods even when steps are taken to use rod guides in the deviated section(s). Submersible pumps sometimes experience electrical harness damage when being inserted on deviated wells which then leads to premature pump failure. Use of a DynaPump (SSI Lift)on such wells allows production to be maintained, or in most cases increased as noted above, but with the pump stroking at approximately ½ the speed of a normal beam pump. Conclusions and Recommendation When rod buckling, rod on tubing wear, rod parts and fluid pound are a problem, then a longer and slower stroke per minute with a smaller plunger size will decrease the failures frequency, improve the performance and increase run life consequently reduces Well Intervention by: Lowering peak polish rod load Reducing the loading by creating higher minimum polish rod load Decreasing buckling tendencies Decreasing side loads and drag loads The effects of rod string compression are expensive and unnecessary, and it can be greatly reduced when long stroke units are utilized.

11 SPE MS 11 Adjustable upstroke and downstroke speeds allow for more pump fillage. Long-stroke sucker-rod pumping units have definite advantages as compared to conventional beam units. They produce greater liquid rates with less downhole pump problems and can also increase the life of the rod string due to the reduced number of stress reversals Ultra-long stroke configuration provides efficient pumping in deep, troublesome, and high-volume wells For high safety and less hazard related to well operation for persons and equipment, the Skid Mounted units are proved to be the best choice. Where all well operation can be done from the power skid Acknowledgements The authors wishes to express their thanks to Tundra Process Solutions and SSi Lift Company for permission to publish this paper. Especially thanks for all SSi Team for their constructive advice and support. Nomenclature API Rod Tapered rod string stared with 1" rod at the top, 7/8" rod at the middle and ¾" rod at the string 86 bottom BPD Barrel per day BFPD Barrel fluid per day BS&W Basic sediment and water BWPD Barrel water per day ESP Electrical submersible pump ft Feet GOR Gas oil ratio HMI Human Machine Interface HP Horse power Ibs Pounds in Inch MMSTBO Million stock tank barrel oil MPRL Minimum polished rod load OPEX Operating Expenses PLC Programmable Logic Controller PPRL Peak polished rod load PSI pound per square inch VFD Variable frequency drive SAGD steam-assisted gravity drainage SR Sucker rod STB Stock tank barrel UHS Ultra high strength References 1. McCaslin, K. P.: "A Study of the Methods for Preventing Rod-Wear Tubing Leaks in Sucker-Rod Pumping Wells, " SPE. November, Rosman, A., DynaPump Inc., "Computer Controlled Long Stroke Pump System", PCOS Paper #3, 4/21/ "Rotaflex Long Stroke Pumping Units." Weatherford Artificial Lift Systems brochure

12 12 SPE MS 4. Kuhns, J. P. Rizzone, M. L.: "Well-Pumping Apparatus." US Patent 3,285,081, Gault, R. H.: "Longstroke Pumping Apparatus for Oil Wells." US Patent 4,076,218, Tait, H. C.: A Rod Pumping System for California Lift Requirements." Paper SPE presented at the California Regional Meeting held in Ventura, California, March 23-25, Lively, G. R.: "Long Stroke Well Pumping Unit with Carriage." US Patent 4,916, Rosman, A. H.: "Hydraulically Operated Lift Mechanism." US Patent 4,801, Rosman, A. H.: "Oil-Well Pumping System or the Like." US Patent 4,848, Rosman, A., DynaPump Inc., "Computer Controlled Long Stroke Pump System", PCOS Paper #3, 4/21/ Brown, K. E., "Overview of Artificial Lift Systems," Journal of Petroleum Technology, October, 1982, pp Guirados, C.; Sandoval, J. Rivas, O. and Troconis, H., "Production Optimization of Sucker Rod Pumping Wells Producing Viscous oil in Boscan Field, Venezuela," SPE 29536, The Production Operation Symposium, Oklahoma City, Ok, 1995; 13. Hirschfeldt, M., Martinez, P., and Distel, F. "Artificial Lift Systems Overview and Evolution in a Mature Basin: Case Study of Golfo San Jorge," SPE , the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos, Argentina, April Ghareeb, M., Shedid, S. A., Ibrahim, M., "Simulation Investigations for Enhanced Performance of Beam Pumping System for Deep High Volume Wells," SPE , the 2007 International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, June, Byrd, J. P.: "Pumping Deep Wells with a Beam and Sucker Rod System". Paper SPE 6436 presented at the Deep Drilling and Production Symposium of the SPE, Amarillo, Texas April 17-19, Pope, C. D. "Optimizing high volume sucker rod lift," SPE 25421, the SPE production Operation Symposium, Oklahoma City, OK, Clegg, J. D.: "High-Rate Artificial Lift". JPT March Ghareeb, M., Shedid, S. A., Ibrahim, M., "Beam Pump System for Deep and High Volume Wells," Egypt Journal for Oil & Gas, Issue 2, February, 2007, pp Gott, C. I.: "Successful Rod Pumping at 14,500 ft". Journal of SPE Production Engineering, November 1986, pp Rowlan, O. L., Lea, J. F., McCoy, J. N., "Overview of Beam Pump Operations," the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, November Henderson, L. J.: "Deep Sucker Rod Pumping for Gas Well Unloading," Paper SPE 13199, the 59th Annual Technical Conference and Exhibition of SPE, Houston, Texas September 16-19, Dr. James F. Lea and Mack Mahoney "Downhole Sucker Rod Pumps Sand and Solids Handling 23. Ron Cramer, Cleon Dunham and Alley Al Hinai, Real time automation optimizes production economics in Oman 24. Jeffrey DaCunha, Nael Sadek, Joe Alexander, Innovative method of Well Testing Beam pumping wells". 25. Jun Xu, "Design and Analysis of Deviated Rod-Pumped Wells" Asia Pacific Oil and Gas Conference and Exhibition held in Brisbane, Australia, October Brown, K.E Overview of Artificial Lift Systems. J Pet Technol 34 (10): SPE-9979-PA Clegg, J.D., Bucaram, S.M., and Hein, N.W.J Recommendations and Comparisons for Selecting Artificial-Lift Methods. J Pet Technol 45 (12): SPE PA. dx.doi.org/ /24834-pa.

13 SPE MS Neely, B., Gipson, F., Clegg, J. et al Selection of Artificial Lift Method. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October SPE MS Clegg, J.D., Bucaram, S.M. and Hein, N.W., New Recommendations and Comparisons for Artificial Lift Method Selection, SPE 24834; and Journal of Petroleum Technology, 1128, December Etherton, J.H. and Thornton, P., A Case Study of the Selection Procedure for Artificial Lift in a High Capacity Reservoir, SW Petroleum Short Course Kol, H. and Lea, J.F., Selection of the Most Effective Artificial List System for the Priobskoye Field, SPE ESP Workshop, April 26-28, Houston, TX Johnson, L.D., Selection of Artificial Lift for a Permian Basin Waterflood, SW Petroleum Short Course, Lubbock,

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