1. 1 Artificial Lift PTRT 2325_Artificial Lift Chapter 01_C Source: WWW

2. 2 Types of Artificial Lift Introduction Beam Pumping – Sucker Rod Pumping Electric Submersible Pumps – ESP Subsurface Hydraulic Pumps Progressing Cavity Pumps – PCP Gas Lift Plunger Lift x sucker-rod (beam) pumping, ESP, gas lift, and reciprocating and jet hydraulic pumping systems. Also, plunger lift and PCP are becoming more common. x Source: Artificial Lift

3. 3 Basics of Artificial Lift When the reservoir pressure falls below the pressure that is necessary to bring petroleum fluids to the surface sum form of artificial means must be employed to bring fluids to the surface The process of bringing lower pressure fluids to the surface is termed artificial lift x Source: Artificial Lift

4. 4 Introduction to Artificial Lift Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

5. 5 Introduction to Artificial Lift It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

6. 6 Introduction to Artificial Lift Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

7. 7 Introduction to Artificial Lift To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected The methods historically used to select the lift method for a particular field vary broadly across the industry. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

8. 8 Introduction to Artificial Lift The manner utilized to select the best artificial lift methods include - operator experience - what methods are available for installations in certain areas of the world - what is working in adjoining or similar fields - determining what methods will lift at the desired rates and from the required depths - evaluating lists of advantages and disadvantages - "expert" systems to both eliminate and select systems - evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value basis. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

9. 9 Introduction to Artificial Lift These methods consider geographic location, capital cost, operating cost, production flexibility, reliability, and "mean time between failures." In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. Also, the equipment and services available from vendors can easily determine which lift method will be applied. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

10. 10 Introduction to Artificial Lift When significant costs for well servicing and high production rates are a part of the scenario, it becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. If the "best" lift method is not selected, such factors as long-term servicing costs, deferred production during workovers, and excessive energy costs (poor efficiency) can reduce drastically the net present value (NPV) of the project. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

11. 11 Introduction to Artificial Lift Typically, the reserves need to be produced in a timely manner with reasonably low operating costs Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project Good data are required for a complete present-value analysis, and these data are not always broadly available. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

12. 12 Introduction to Artificial Lift In some situations, the type of lift already has been determined and the task is to best apply that system to the particular well The more basic question, however, is how to determine the proper type of artificial lift to apply in a given field for maximum present value profit (PVP) This chapter briefly reviews each of the major types of artificial lift before examining some of the selection techniques Some less familiar methods of lift also are mentioned Preliminary factors related to the reservoir and well conditions that should be considered are introduced Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

13. 13 Introduction to Artificial Lift Environmental and geographical considerations may be overriding issues in the determination of the lift method Sucker-rod pumping is, by far, the most widely used artificial lift method in onshore United States operations However, in a densely populated city or on an offshore platform with 40 wells in a very small deck area, sucker- rod pumping might be a poor choice. Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

14. 14 Introduction to Artificial Lift Deep wells producing several thousands of barrels per day cannot be lifted by beam lift; therefore, other methods must be considered Such geographic, environmental, and production considerations can limit the choices to only one method of lift Determining the best overall choice is more difficult when it is possible to apply several of the available lift methods. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

15. 15 Artificial Lift x Beam Pumping Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

16. 16 Beam Pumping Beam pumping is the most common method of bringing subsurface oil to the surface Beam pumping involves both surface and subsurface equipment The pumping action is derived from the rotary motion of a prime mover (electric motor) into an up-and-down motion that actuates a below surface pump the forces oil to the surface x x sucker-rod (beam) pumping, ESP, gas lift, and reciprocating and jet hydraulic pumping systems. Also, plunger lift and PCP are becoming more common. Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

17. 17 Pump Jack Source: www Artificial Lift

18. 18 Pump Jack Source: www Artificial Lift

19. 19 Pump Jacks Source: www Artificial Lift

20. 20 Pump Jack Oil Pumping System Source: www x Artificial Lift

21. 21 Beam Pumping – Sucker Rod Pumping Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Schematic of a beam-pumping system. (from Harbison-Fischer) Artificial Lift

22. 22 Sucker-rod pumping systems are the oldest and most widely used type of artificial lift for oil wells x Beam Pumping – Sucker Rod Pumping Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

23. 23 There are approximately 2 million oil wells in operation worldwide More than 1 million wells use some type of artificial lift More than 750,000 of the lifted wells use sucker-rod pumps In the U.S., sucker-rod pumps lift approximately 350,000 wells. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Beam Pumping – Sucker Rod Pumping Artificial Lift

24. 24 Approximately 80% of all U.S. oil wells are stripper wells making less than 10 B/D with some water cut. (date???) The vast majority of these stripper wells are lifted with sucker-rod pumps Of the nonstripper "higher" volume wells, 27% are rod pumped, 52% are gas lifted, and the remainder are lifted with ESPs, hydraulic pumps, and other methods of lift These statistics indicate the dominance of rod pumping for onshore operations For offshore and higher-rate wells around the world, the use of ESPs and gas lift is much higher. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Beam Pumping – Sucker Rod Pumping Artificial Lift

25. 25 Sucker-rod pumping systems should be considered for new, lower volume stripper wells because they have proved to be cost effective over time In addition, operating personnel usually are familiar with these mechanically simple systems and can operate them efficiently Inexperienced personnel also can operate rod pumps more effectively than other types of artificial lift Sucker-rod pumping systems can operate efficiently over a wide range of production rates and depths Most of these systems have a high salvage value x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Considerations for Use of Sucker Rod Pumping Artificial Lift

26. 26 Sucker-rod systems should be considered for lifting moderate volumes from shallow depths and small volumes from intermediate depths. It is possible to lift up to 1,000 B/D from approximately 7,000 ft and 200 bbl from approximately 14,000 ft. Special rods may be required, and lower rates may result depending on conditions. Most of the sucker-rod pumping system parts are manufactured to meet existing standards, which have been established by the American Petroleum Institute (API). Numerous manufacturers can supply each part, and all interconnecting parts are compatible. Many components are manufactured and used that are not API certified, such as large-diameter downhole pumps extending to more than 6 in. in diameter. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Considerations for Use of Sucker Rod Pumping Artificial Lift

27. 27 x x x The sucker-rod string is the length of the rods from the surface to the downhole pump, and it continuously is subjected to cyclic load fatigue typical of sucker-rod pump systems. The system must be protected against corrosion, as much as any other artificial lift system, because corrosion introduces stress concentrations that can lead to early failures. Frequent rod failures must be avoided for an economical system operation. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

28. 28 x x x Sucker-rod pumping systems often are most incompatible with deviated (doglegged) wells, even with the use of rod protectors and rod and/or tubing rotators. However, deviated wells with smooth profiles and low dogleg severity may allow satisfactory sucker-rod pumping, even if the angle at the bottom of the well is large (approximately 30 to 40°, up to 80°). Some high-angle hole systems use advanced methods of protecting the tubing and rod string with rod protectors and "roller-rod protectors," while other installations with high oil cuts, smooth profiles, and lower angles of deviation use only a few of these devices. Plastic-lined tubing has proven to be effective in reducing rod/tubing wear. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

29. 29 x x x Sucker-rod pumping systems often are most incompatible with deviated (doglegged) wells, even with the use of rod protectors and rod and/or tubing rotators. However, deviated wells with smooth profiles and low dogleg severity may allow satisfactory sucker-rod pumping, even if the angle at the bottom of the well is large (approximately 30 to 40°, up to 80°). Some high-angle hole systems use advanced methods of protecting the tubing and rod string with rod protectors and "roller-rod protectors," while other installations with high oil cuts, smooth profiles, and lower angles of deviation use only a few of these devices. Plastic-lined tubing has proven to be effective in reducing rod/tubing wear. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

30. 30 x x x One of the disadvantages of a beam-pumping system is that the polished-rod stuffing box, in which a polished rod with the rods hung below enters the well at the surface through a rubber packing element, can leak. This can be minimized with special pollution-free stuffing boxes that collect any leakage. Good operations, with such practices as "don’t over tighten" and "ensure unit alignment with standard boxes," with standard boxes are also important. Continuous production with the system attempting to produce more than the reservoir will produce leads to incomplete pump filling of the pump, fluid pound, mechanical damage, and low energy efficiency. Many systems are designed to produce 120 to 150% more than the reservoir will produce, but when the well is pumped down, a pumpoff controller will stop pumping temporarily to allow fluid entry into the casing-tubing annulus over the pump. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

31. 31 x x x In general, sucker-rod pumping is the method of artificial lift that should be used if the system can be designed without overloading the prime mover, gearbox, unit structure, and the calculated fatigue loading limits of the rods. This system should be considered very carefully in the selection process and, in many cases, should be the artificial lift system of choice. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems x Artificial Lift

32. 32 Beam Pumping Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems x Artificial Lift

33. 33 Electrical Submersible Pumping x As an example area in which ESPs are applied extensively, THUMS Long Beach Co. was formed in April 1965 to drill, develop, and produce the 6,479-acre Long Beach unit in Wilmington field, Long Beach, California. It was necessary to choose the best method to lift fluids from the approximately 1,100 deviated wells over a 35- year contract period from four man-made offshore islands and one onshore site. ESPs have been the primary system in this environment for the contract period. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems x Artificial Lift

34. 34 Artificial Lift x Electrical Submersible Pumping Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

35. 35 x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Electrical Submersible Pumping x Artificial Lift

36. 36 x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Electrical Submersible Pumping Artificial Lift

37. 37 x x Source: www Schlumberger Electric submersible pump system Artificial Lift

38. 38 x x Major ESP Advantages. ESPs provide a number of advantages. Adaptable to highly deviated wells; up to horizontal, but must be set in straight section. Adaptable to required subsurface wellheads 6 ft apart for maximum surface-location density. Permit use of minimum space for subsurface controls and associated production facilities. Quiet, safe, and sanitary for acceptable operations in an offshore and environmentally conscious area. Generally considered a high-volume pump. Provides for increased volumes and water cuts brought on by pressure maintenance and secondary recovery operations. Permits placing wells on production even while drilling and working over wells in immediate vicinity x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Electrical Submersible Pumping Artificial Lift

39. 39 x x Major ESP Disadvantages. ESPs have some disadvantages that must be considered. Will tolerate only minimal percentages of solids (sand) production, although special pumps with hardened surfaces and bearings exist to minimize wear and increase run life. Costly pulling operations and lost production occur when correcting downhole failures, especially in an offshore environment. Below approximately 400 B/D, power efficiency drops sharply; ESPs are not particularly adaptable to rates below 150 B/D. Need relatively large (greater than 4½-in. outside diameter) casing size for the moderate- to high-production-rate equipment. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Electrical Submersible Pumping Artificial Lift

40. 40 Long life of ESP equipment is required to keep production economical. Improvements and recommendations based on experience are in the chapter on ESP in this section of the Handbook and in "ABB Automation Technology Products Presentation." [4] [4] x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Electrical Submersible Pumping Artificial Lift

41. 41 Artificial Lift x Progressive Cavity Pumping – PCP Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

42. 42 PCP and the Electrical Submersible Progressive Cavity Pump x x The PCP and the Electrical Submersible Progressive Cavity Pump Fig. 10.5 shows a schematic of a PCP with a rotating metal rotor and a flexible rubber-molded stator. The stator forms a cavity that moves up as the rotor turns. The pump is well suited for handling solids and viscous fluids because the solids that move through the pump may deflect the rubber stator but do not abrade, wear, or chemically deteriorate the stator or rotor to any appreciable degree. Most PCPs are powered by rotating rods driven from the surface with a hydraulic or electric motor. The system shown in Fig. 10.5 has a pump small enough that the entire pump can be inserted with rods. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

43. 43 x x x Introduced in 1936, the PCP is of simple design and rugged construction. Its low (300 to 600 rev/min) operating speeds enable the pump to maintain long periods of downhole operation if not subjected to chemical attack or excessive wear or it is not installed at depths greater than approximately 4,000 to 6,000 ft. The pump has only one moving part downhole with no valves to stick, clog, or wear out. The pump will not gas lock, can easily handle sandy and abrasive formation fluids, and is not normally plugged by paraffin, gypsum, or scale. With this system, the rotating rods wear and also wear the tubulars. The rotating rods "wind" up on start and "unwind" on the shutdown. Rotating rods must be sealed at the surface, and many installations have oil leaks at the surface. These problems must be addressed during system design. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

44. 44 x x x To alleviate problems inherent with the conventional rotating-rod PCP systems, the ESPCP system is available. While the number installed is still small, this is not a new system. It has been run in Russia for a number of years and also was available from an ESP vendor a number of years ago. The newer ESPCP system (Fig. 10.6) has some advantages over the rotating sucker-rod systems. x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems x Artificial Lift

45. 45 x x x Fig. 10.6—Schematic of ESPCP system. (Courtesy of Centrilift.) Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems x Artificial Lift

46. 46 x x x There is a problem of rotating the eccentric rotor with the motor shaft because of possible vibration; therefore, a flexible connection is used. There is a seal section, as in an ESP assembly, to protect the underlying motor from wellbore fluids and to accommodate an internal thrust bearing. Because the PCP usually rotates at approximately 300 to 600 rev/min, and the ESP motor rotates at approximately 3,500 rev/min under load, there must be a way of reducing speed before the shaft connects to the PCP. Methods available from various manufacturers include the use of a gearbox to reduce the motor to acceptable speeds (less than approximately 500 rev/min). Another method is to use higher pole motors with lower synchronous speeds to allow the PCP to turn at operational speeds in combination with a gearbox, but this system produces less output- starting torque x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

47. 47 x x x Major PCP Advantages. PCPs have the following major advantages. The pumping system can be run into deviated and horizontal wells. The pump handles solids well, but the coating of the rotor will erode over time. The pump handles highly viscous fluids in a production well with a looser rotor/stator fit. Several of the components are off-the-shelf ESP components for the ESPCP. The production rates can be varied with the use of a variable-speed controller with an inexpensive downhole-pressure sensor. For appropriate conditions, the PCP can operate with a power efficiency exceeding other artificial lift methods. The PCP can be set in a straight section of a deviated well. Use of an ESPCP eliminates the rotating rods and eliminates problems with rods rotating in a deviated well. x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

48. 48 x x x Major PCP Disadvantages. PCPs have the following disadvantages. The stator material will have an upper temperature limit and may be subject to H 2 S and other chemical deterioration. Frequent stops and starts of the PCP pumps often can cause several operating problems. Although it will not gas lock, best efficiency occurs when gas is separated. If the unit pumps off the well or gas flows continuously though the pump for a short period, the stator will likely be permanently damaged from overheating caused by gas compression. The gearbox in an ESPCP is another source of failure if wellbore fluids or solids leak inside it or if excessive wear occurs x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

49. 49 x x x Progressive Cavity Pump Summary. For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150°F typical, approximately 250°F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

50. 50 Artificial Lift x Gas Lift Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

51. 51 Gas Lift Gas lift is used extensively around the world and dominates production in the U.S. Gulf Coast with most these wells are on continuous-flow gas lift The principle of gas lift is that gas injected into the tubing reduces the density of the fluids in the tubing, and the bubbles have a "scrubbing" action on the liquids Both factors act to lower the flowing BHP at the bottom of the tubing Care must be exercised not to inject excess gas, or friction will begin to negate the desirable effects of injecting gas into the tubing. x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

52. 52 Continuous-Flow Gas Lift Continuous-flow gas lift is recommended for high- volume and high-static BHP wells in which major pumping problems could occur with other artificial lift methods It is an excellent application for offshore formations that have a strong waterdrive, or in waterflood reservoirs with good PIs and high gas/oil ratios (GORs). If high-pressure gas without compression is available or when gas cost is low, gas lift is especially attractive. Continuous-flow gas lift supplements the produced gas with additional gas injection to lower the intake pressure to the tubing, resulting in lower formation pressure as well x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

53. 53 Schematic of a gas lift system. (photo from Schlumberger.) Gas Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

54. 54 A reliable, adequate supply of good quality high- pressure lift gas is mandatory This supply is necessary throughout the producing life of the well if gas lift is to be maintained effectively In many fields, the produced gas declines as water cut increases, requiring some outside source of gas The gas-lift pressure typically is fixed during the initial phase of the facility design. x x Gas Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

55. 55 Ideally, the system should be designed to lift from just above the producing zone Wells may produce erratically or not at all when the lift supply stops or pressure fluctuates radically Poor gas quality will impair or even stop production if it contains corrosives or excessive liquids that can cut valves or fill low spots in delivery lines The basic requirement for gas must be met, or gas lift is not a viable lift method. x x Gas Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

56. 56 Continuous-flow gas lift imposes a relatively high backpressure on the reservoir compared with pumping methods; therefore, production rates are reduced Also, power efficiency is not good compared with some artificial lift methods, and the poor efficiency significantly increases both initial capital cost for compression and operating energy costs. x x Gas Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

57. 57 Gas lift is the best artificial lift method for handling sand or solid materials. Many wells produce some sand even if sand control is installed The produced sand causes few mechanical problem in the gas-lift system; whereas, only a little sand plays havoc with other pumping methods, except the PCP type of pump Deviated or crooked holes can be lifted easily with gas lift. This is especially important for offshore platform wells that are usually drilled directionally. x x Gas Lift – Advantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

58. 58 Gas lift permits the concurrent use of wireline equipment, and such downhole equipment is easily and economically serviced. This feature allows for routine repairs through the tubing. The normal gas-lift design leaves the tubing fully open. This permits the use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc x x Gas Lift - Advantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

59. 59 High-formation GORs (gas/oil ratios) are very helpful for gas-lift systems but hinder other artificial lift systems. Produced gas means less injection gas is required; whereas, in all other pumping methods, pumped gas reduces volumetric pumping efficiency drastically. Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow also can be easily accomplished to handle exceedingly high volumes. A central gas-lift system easily can be used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing x x Gas Lift - Advantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

60. 60 x x A gas-lift system is not obtrusive; it has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering. The low profile is usually an advantage in urban environments. Well subsurface equipment is relatively inexpensive. Repair and maintenance expenses of subsurface equipment normally are low. The equipment is easily pulled and repaired or replaced. Also, major well workovers occur infrequently. Installation of gas lift is compatible with subsurface safety valves and other surface equipment. The use of a surface-controlled subsurface safety valve with a ¼-in. control line allows easy shut in of the well. Gas lift can still perform fairly well even when only poor data are available when the design is made. This is fortunate because the spacing design usually must be made before the well is completed and tested. x Fundamentals of Petroleum x Gas Lift - Advantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems

61. 61 Relatively high backpressure may seriously restrict production in continuous gas lift. This problem becomes more significant with increasing depths and declining static BHPs. Thus, a 10,000-ft well with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be difficult to lift with the standard continuous-flow gas-lift system. However, there are special schemes available for such wells. Gas lift is relatively inefficient, often resulting in large capital investments and high energy-operating costs. Compressors are relatively expensive and often require long delivery times. The compressor takes up space and weight when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas use also may increase the size of necessary flowline and separators. x x Gas Lift - Disadvantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

62. 62 Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas becomes too expensive, it may be necessary to switch to another artificial lift method. In addition, there must be enough gas for easy startups. Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%). There is increased difficulty when lifting low gravity (less than 15°API) crude because of greater friction, gas fingering, and liquid fallback. The cooling effect of gas expansion may further aggravate this problem. Also, the cooling effect will compound any paraffin problem. Good data are required to make a good design. If not available, operations may have to continue with an inefficient design that does not produce the well to capacity. x x Gas Lift - Disadvantages Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

63. 63 Gas Lift x x This section addresses the following issues: Why choose gas lift?; Where should continuous flow be used?; and When should intermittent lift be selected? x Source: PETEX_Fundamentals of Petroleum_5 th _Denehy x Artificial Lift

64. 64 Artificial Lift x Plunger Lift Source: PETEX_Fundamentals of Petroleum_5 th _Denehy Artificial Lift

65. 65 Plunger Lift Plunger lift is commonly used to remove liquids from gas wells or produce relatively low volume, high GOR oil wells. Plunger lift is important and, in its most efficient form, will operate with only the energy from the well. A free-traveling plunger and produced-liquid slug is cyclically brought to the surface of the well from stored gas pressure in the casing-tubing annulus and from the formation. In the off cycle, the plunger falls and pressure builds again in the well. x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

66. 66 Plunger Lift A new two-piece plunger (cylinder with ball underneath) can lift fluids when the components are together But both components are designed to fall when separate Use of this plunger allows a shut-in portion of the operational cycle that is only a few seconds long, resulting in more production for many wells. x x Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

67. 67 Schematic of a plunger lift installation. Plunger Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift

68. 68 There is a chamber pump that relies on gas pressure to periodically empty the chamber and force the fluids to the surface, which is essentially a gas-powered pump There are variations of gas lift and intermittent lift, such as chamber lift The principles presented apply to the selection of all methods that might be considered. x x Plunger Lift Source: http://petrowiki.spe.org/PEH%3AArtificial_Lift_Systems Artificial Lift