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Difference between revisions of "Sucker-rod pumping units"

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<ref name="r5">AGMA 2001-C95, Fundamental Rating Factors and Calculation Method for Involute, Spur and Helical Gear Teeth. 2001. Alexandria, Virginia: American Gear Manufacturers Association. </ref>
 
<ref name="r5">AGMA 2001-C95, Fundamental Rating Factors and Calculation Method for Involute, Spur and Helical Gear Teeth. 2001. Alexandria, Virginia: American Gear Manufacturers Association. </ref>
 
<ref name="r6">Zaba, J. 1962. ''Modern Oil Well Pumping''. Tulsa, Oklahoma: Petroleum Publishing Co. </ref>
 
<ref name="r6">Zaba, J. 1962. ''Modern Oil Well Pumping''. Tulsa, Oklahoma: Petroleum Publishing Co. </ref>
<ref name="r7">Saber, T. 1993. ''Modern Sucker Rod Pumping''. Tulsa, Oklahoma: PennWell Books. </ref>
+
<ref name="r7">Takacs, G. 1993. ''Modern Sucker Rod Pumping''. Tulsa, Oklahoma: PennWell Books. </ref>
 
<ref name="r8">API RP 11L, Recommended Practice for Design Calculations for Sucker Rod Pumping Systems, fourth edition, Errata 1. Washington, DC: API, Washington DC. </ref>
 
<ref name="r8">API RP 11L, Recommended Practice for Design Calculations for Sucker Rod Pumping Systems, fourth edition, Errata 1. Washington, DC: API, Washington DC. </ref>
 
<ref name="r9">Svinos, J.G. 1983. Exact Kinematic Analysis of Pumping Units. Presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, USA, 5–8 October. SPE-12201-MS. http://dx.doi.org/10.2118/12201-MS </ref>
 
<ref name="r9">Svinos, J.G. 1983. Exact Kinematic Analysis of Pumping Units. Presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, USA, 5–8 October. SPE-12201-MS. http://dx.doi.org/10.2118/12201-MS </ref>

Revision as of 10:37, 16 October 2013

Many devices are connected to the downhole sucker-rod equipment through the polished rod on the surface that imparts the reciprocating motion to the rod string and pump. In the history of sucker-rod pumping, a standalone, surface pumping unit has become the proven technology. Many pumping unit types are commercially available. Those most widely used have a walking beam as the horizontal load-bearing element and a sampson post that vertically supports the beam. These terminologies and configurations were adapted from the cable-tool drilling rigs used to drill early oil wells and developed into the conventional pumping unit.

API has standardized the design, terminology, and many components used for pumping units in API Spec. 11E. [1] ISO accepted the use of this standard as a base to fast track the publication of ISO Standard 10431. [2] Currently, these are comparable standards and cover the two main components making up a pumping unit: the gear reducer and the structure. They are standardized separately because the gear-reducer manufacturer may be separate from the structural manufacturer, who would be responsible for the assembly.

Unit designation

A pumping unit results when the gear reducer and the structure are combined together. These units have a size rating that describes the unit's capacities with the reducer rating, maximum structural capacity, and the maximum stroke length. The reducer number is the maximum torque rating in lbf-in. divided by 1,000. The structure number is the maximum load normally on the beam in lbf divided by 100, while the maximum stroke length is in inches. This results in a three-number hyphenated description that ranges from 6.4-21-24 to 3,648-470-300 for the 77 possible standardized units. These describe the smallest unit with a 6,400-lbf-in. reducer, a 2,100-lbf structure capacity, and 24-in. stroke to the largest unit with a 3,648,000-lbf-in. reducer, 47,000-lbf structure, and 300-in. stroke. However, not all of these unit sizes are available from all manufacturers in all the possible structural geometries.

The commercially available units are further described by adding the structural type or geometry and possibly the type of gear reducer [single (no letter) or double (D)]. Normally,

  • B is for a beam-balanced conventional unit
  • C is for a conventional crank-balanced unit
  • A is for an air-balanced unit
  • M is for a Mark IITM unit
  • RM is for Reverse MarkTM unit

An example designation for a conventional, crank-balanced pumping unit with a 456,000-lbf-in. double-reduction-gear reducer, a 30,500-lbf structure, and a maximum stroke length of 168 in. would be C456D-305-168.

Manufacturers should be contacted for their normal availability, special designs, sizes, and types of units they sell. However, Table 1 shows the minimum and maximum size ranges commercially available from a large US manufacturer. [3]

Gear reducer

There are 18 gear-reducer sizes currently included in API Spec. 11E. [1] The size range is from 6.4- to 3,648- or 6,400- to 3,648,000-lbf-in. capacity. When these gear reducers are put in their operating enclosure and attached to a pumping-unit structure, then this equipment is normally called a gearbox. Pumping units typically use single- or double-reduction gearing, with an approximate 30:1 speed reduction from the prime-mover to the pumping speed. The standards also include chain reducers that use sprockets and chains for transmitting the prime-mover speed through the structure to the rod string. These are available as single-, double-, and triple-reduction drives. While this is still a possible reducer design, they are limited in capacity and are not normally used.

Gear ratings for speed and life

Sucker-rod pumping units can be operated over a range of pumping speeds. It has been recognized that there is a need for a nominal pumping speed to rate the various gear reducers. Originally, the industry adopted a nominal speed of 20 spm. This assumed that the up and down stroke of a unit forms one complete stroke cycle.

As API Spec. 11E has been revised over time, rating speed for the 456- and larger-sized reducers has been reduced because it was not practical to expect larger gearboxes to operate at 20 spm with longer stroke lengths and larger-sized structures. In actuality, industrial applications with these similar-sized reducers can be operated from 580 to 1,750 rpm. American Gear Manufacturer's Association (AGMA) Standard 422.03, [4] which is the basis for API Spec. 11E, limits the speed of the reducer to either the pitch-line velocity of any stage to 5,000 ft/min and/or the speed of any shaft to less than 3,600 rpm.

It should be noted that none of the industry standards from API, ISO, or AGMA[5] address a required reducer life; however, the operating rule of thumb is an expected 20 to 25 years of life. This assumes the gearbox is not overloaded or abused and is properly maintained. One pumping unit manufacturer has developed a graph (shown in Fig. 2) depicting the effect on gearbox life from overloading the gearbox capacity (based on personal communication with C. Hunt, Lufkin Industries). This shows that, while current API designed and manufactured reducers may be overloaded without catastrophic failure, depending on the amount of overload, the expected life should be reduced.

AGMA Standard 2001-C95[5] provides a way to calculate tooth stress that should provide satisfactory operation for a reasonable time. If the existing calculations are used and worked backwards to calculate the life of an acceptable design, then a reducer life of more than 4 × 108 cycles should be expected at the rated torque load. This would result in a life—assuming a constant 10-spm pumping-unit speed for every day of the year—of more than 76 years. However, this still assumes proper gear-reducer installation, operation, and maintenance.

Standard structures

The industry standards for pumping units have developed minimum requirements for the design and manufacture of the various structured components—the beams, shafting, hanger, brakes, horsehead, cranks, and bearings. The four main standard pumping-unit structural geometries covered by API Spec. 11E are as follows:

  • Rear-mounted geometry, Class I lever systems with crank counterbalance.
  • Front-mounted geometry, Class III lever systems with crank counterbalance.
  • Front-mounted geometry, Class III lever systems with air counterbalance.
  • Rear-mounted geometry, Class I lever systems with phased-crank counterbalance.

These standardized structures are more widely known by the respective designations:

  • Conventional
  • Mark IITM
  • Air balanced
  • Reverse MarkTM

There are variations of these geometries, such as for slant wells or as low profile for overhead irrigated fields. Additionally, there are special geometries or structures that are based on hydraulics, pneumatics, or belts. Because these structures are not covered by industry standards, it is recommended that these special units are designed properly, manufactured to industry quality standards, and installed and operated according to the manufacturer’s recommendations.

Unit selection

There have been many publications about the advantages, disadvantages, and selection of the various standard geometries and the specialty pumping units, including the following:

Below is a brief summary and comparison of the four standard pumping units.

The conventional unit is probably the unit used most often. It is simple to install, has the widest range of sizes available, usually has lower operating costs than other units, needs no hoisting equipment or rigid supports for changing stroke length, and can run faster in wells in which free fall limits pumping speed. The maximum pumping speed for the conventional unit in an average well is estimated at 70% of the maximum free fall of rods in air. This compares with 63% for air-balanced units and 56% for Mark IITM units. The free-fall speed is defined for the conventional unit by the following formula:

Vol4 page 0492 eq 001.png....................(1)

The free-fall speed is reduced by 10 and 20% for the air-balanced and Mark IITM units, respectively. This means that in a well with average friction and a 100-in. polished-rod stroke, the rods will fall a maximum of 17.15 spm with a conventional unit, 15.43 spm with an air-balanced unit, and 13.72 spm for the Mark IITM. However, there should be no separation between the carrier bar of the unit and the polished-rod clamp during the downstroke. These speeds would be further reduced in wells with increased friction from composite-ring-type plungers, deviated holes, particulates sticking the downhole pump, and/or very viscous crude. Furthermore, the conventional unit's geometry allows either clockwise or counterclockwise rotation. This may be beneficial for gear teeth that are damaged in one direction from poor operation or maintenance and may enable rotating in the opposite direction. This would extend the life of the gearbox.

Air-balanced units use a leverage system different from conventional units. The use of compressed air instead of heavy, cast-iron counterweights allows more-accurate fingertip control of the counterbalance, which can be adjusted without stopping the unit. With no counterweights, the unit weighs much less than a comparably sized conventional unit. It also has a lighter substructure and a slightly lighter beam. Thus, there are several advantages to its compact size and light weight, especially for portable test units and for use on offshore platforms. It also uses more degrees of crank travel to complete the first one-half of the upstroke, which tends to decrease the peak load. This is a slight advantage if rod fatigue is a problem. However, there are increased maintenance problems or concerns, especially with leakage past the piston, which may make it difficult to maintain the proper air pressure. Additionally, the leakage also may cause an oil spray and resulting environmental consideration. Further, water condensation in the air system may cause damage if it is allowed to freeze, unless proper antifreeze is used.

The Mark IITM unit has an equalizer bearing between the Samson post and the well load. The equalizer bearing is located ahead or to the well side of the centerline of the slow-speed shaft. This is different from the air-balanced unit in which the equalizer bearing is directly over the slow-speed shaft. The equalizer bearing location results in an upstroke of approximately 195° and a downstroke of 165°. This makes a slower upstroke with 20% less acceleration, which results in reduced peak polished-rod load. The slower upstroke also allows more time for viscous fluids to fill the pump barrel and can increase the pump's volumetric efficiency, but this requires the unit to operate only in the counterclockwise rotation.

While comparably sized Mark IITM units are heavier and more expensive than conventional units, the claimed torque reductions may make it possible to use a Mark IITM unit one size smaller than required for a conventional unit. However, these units should not be used when high pumping speeds or undertravel-type dynamometer cards are anticipated and/or there are crooked or deviated wells. When an undertravel card or a card that showed neither undertravel nor overtravel is developed, the conventional or Reverse Mark unit has a better-suited permissible-load diagram.

The Reverse MarkTM unit is classified as a rear-mounted geometry, Class I lever system with phased-crank counterbalance. The phased cranks improve load-lifting capabilities; thus, like the Mark IITM, this unit may enable a one-size-smaller gear reducer than a conventional unit. However, this rule of thumb needs to be tempered by the actual pumping parameters and resulting dynamometer-card shape. Furthermore, the phase crank also makes this a unidirectional unit.

The other specialty units have their own advantages and disadvantages that may be considered if the standard units are not capable of meeting production-design requirements. Regardless of which unit is selected, a full-cycle economic consideration should be conducted to compare the costs for:

  • Purchase
  • Installation
  • Maintenance
  • Operation
  • Repairs
  • Failure frequency
  • Resale value

These parameters should all be considered, along with the capability of producing the required fluid volume from the required well depth, to decide which unit would be best for a particular well.

Sizing

There have been a variety of methods for determining the required reducer size for a pumping unit, including the "approximate method," "engineering analysis," and kinematics.[1][6][7][8][12][13][14][28] Today, most engineers/operators who select the pumping unit will rely on the output from a rod-string-design program that calculates the peak torque at the polished rod. These are based on the API RP 11L[8] method and the extension to wave equations that allow geometries other than the conventional unit to be considered. Because these calculations provide peak torques at the polished rod, the torque has to be transmitted through the structure and its bearings to the gearbox. However, because these bearings are not 100% efficient, Gipson and Swaim[14] developed curves for selecting the gearbox to account for these inefficiencies; Fig. 1 shows the loss of efficiency curves for both new and used units. Typically, this requires a gearbox approximately 10 or 20% larger in capacity than the peak torque calculated at the polished rod for new or used units, respectively. Once the design's peak-torque capacity is determined, then the closest available, but higher-rated, reducer should be selected. The beam should be selected on the basis of the calculated peak polished-rod load from the rod-string-design program. Finally, the unit stroke length should be selected on the basis of the required pump capacity with a 10 to 20% production cushion.

Specialty pumping units and the required reducer, structural capacity, and the desired stroke length should be discussed with the manufacturer to guarantee unit performance.

Installation, operation and maintenance of pumping units

Many publications have been issued on the installation, operation, maintenance, and lubrication of pumping units. [12][13][54][55][56][57][58][59][60][61][62][63][64][65] These papers have been incorporated into API RP 11G1[66] to reflect the minimum recommended practices considered for installation, operation, and lubrication of the pumping unit. Additionally, manufacturers of the units may have their own documents and recommended procedures for installation, operation, and maintenance that should be followed.

Guards

Properly guarding a pumping unit is of critical importance. The industry standard, American National Standard Institute (ANSI)/API RP 11ER, [67] should be followed when guarding the pumping unit, V-belts, sheaves, flywheels, cranks, counterweights, and moving parts on pumping units. Major pumping-unit manufacturers are also excellent sources of guidance on guarding and can usually supply guards that will meet specific regulatory requirements.

Nomenclature

S = surface stroke length, in.


References

  1. 1.0 1.1 1.2 1.3 API Spec. 11E, Specification for Pumping Units, 17th edition. 1994. Washington, DC: API (November 1994/Reaffirmed January 2000).
  2. ISO Spec. 10431, Specification for Petroleum and Natural Gas Industries—Pumping Units. 1993. ISO.
  3. Oilfield Products Group General Catalog. 2001. Lufkin, Texas: Lufkin Industries Inc.
  4. AGMA 422.03, Practice for Helical and Herringbone Speed Reducers for Oilfield Pumping Units. 1998. Alexandria, Virginia: American Gear Manufacturers Association.
  5. 5.0 5.1 AGMA 2001-C95, Fundamental Rating Factors and Calculation Method for Involute, Spur and Helical Gear Teeth. 2001. Alexandria, Virginia: American Gear Manufacturers Association.
  6. 6.0 6.1 6.2 6.3 Zaba, J. 1962. Modern Oil Well Pumping. Tulsa, Oklahoma: Petroleum Publishing Co.
  7. 7.0 7.1 7.2 7.3 Takacs, G. 1993. Modern Sucker Rod Pumping. Tulsa, Oklahoma: PennWell Books.
  8. 8.0 8.1 8.2 API RP 11L, Recommended Practice for Design Calculations for Sucker Rod Pumping Systems, fourth edition, Errata 1. Washington, DC: API, Washington DC.
  9. Svinos, J.G. 1983. Exact Kinematic Analysis of Pumping Units. Presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, USA, 5–8 October. SPE-12201-MS. http://dx.doi.org/10.2118/12201-MS
  10. 10.0 10.1 Zaba, J. 1943. Oil Well Pumping Methods: A Reference Manual for Production Men. Oil & Gas J (July).
  11. 11.0 11.1 Donnelly, R.W. 1986. Oil and Gas Production: Beam Pumping. Dallas, Texas: PETEX, University of Texas.
  12. 12.0 12.1 12.2 12.3 Frick, T.C. 1962. Petroleum Production Handbook, Vol. 1. Dallas, Texas: Society of Petroleum Engineers.
  13. 13.0 13.1 13.2 Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.
  14. 14.0 14.1 14.2 Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.
  15. Clegg, J.D. 1988. High-Rate Artificial Lift. J Pet Technol 40 (3): 277-282. SPE-17638-PA. http://dx.doi.org/10.2118/17638-PA
  16. Hein Jr., N.W. 1996. Beam-Pumping Operations: Problem Solving and Technology Advancements. J Pet Technol 48 (4): 330-336. SPE-36163-MS. http://dx.doi.org/10.2118/36163-MS
  17. McCoy, J.N., Podio, A.L., Huddleston, K.L. et al. 1985. Acoustic Static Bottomhole Pressures. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 10-12 March 1985. SPE-13810-MS. http://dx.doi.org/10.2118/13810-MS
  18. 18.0 18.1 McCoy, J.N., Podio, A.L., and Becker, D. 1992. Pressure Transient Digital Data Acquisition and Analysis From Acoustic Echometric Surveys in Pumping Wells. Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 18-20 March 1992. SPE-23980-MS. http://dx.doi.org/10.2118/23980-MS
  19. Watson, J. 1983. Comparing Class I and Class III Varying Pumping Unit Geometries. Paper 030 presented at the 1983 Southwestern Petroleum Short Course, Lubbock, Texas, 27–28 April.
  20. Evans, C.E. 1961. What Type of Beam Pumping Unit Would You Use? Paper 015 presented at the 1961 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 20–21 April.
  21. Keiner, C.J. 1962. API Pumping Units. Paper 024 presented at the 1962 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 12–13 April.
  22. Kilgore, J.J., Tripp, H.A., and Hunt Jr., C.L. 1991. Walking Beam Pumping Unit System Efficiency Measurements. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6-9 October 1991. SPE-22788-MS. http://dx.doi.org/10.2118/22788-MS.
  23. Byrd, J.P. and Jackson, B.C. 1962. Field Testing a Front-Mounted Mechanical Oilfield Pumping Unit. Presented at the Rocky Mountain Joint Regional Meeting, Billings, Montana, SPE-382-MS. http://dx.doi.org/10.2118/382-MS
  24. Byrd, J. 1968. High Volume Pumping with Sucker Rods. J Pet Technol 20 (12): 1355–1360. SPE-2104-PA. http://dx.doi.org/10.2118/2104-PA
  25. Nolen, K.B. 1969. Deep High Volume Rod Pumping. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Denver, Colorado, 28 September-1 October. SPE-2633-MS. http://dx.doi.org/10.2118/2633-MS
  26. Gipson, F.W. 1990. Maximum Capacity of Beam Pumping Equipment and High Strength Steel Sucker Rods. Paper 026 presented at the 1990 Southwestern Petroleum Short Course, Lubbock, Texas, 18–19 April.
  27. Gault, R.H. 1961. Pumping Unit Geometry. Paper 002 presented at the 1961 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 20–21 April.
  28. 28.0 28.1 Byrd, J.P. 1970. The Effectiveness of a Special Class III Lever System Applied to Sucker Rod Pumping. Paper 009 presented at the 1970 Southwestern Petroleum Short Course, Lubbock, Texas, 16–17 April.
  29. Richards, C. 1956. Application of Air Balance Pumping Units. Paper 019 presented at the 1956 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 15–16 April.
  30. Byrd, J.P. 1990. History, Background and Rationale of the Mark II Beam Type Oil Field Pumping Unit. Paper 024 presented at the 1990 Southwestern Petroleum Short Course, Lubbock, Texas, 18–19 April.
  31. Byrd, J.P. 1962. Recent Advances in Beam Type Unit Designs. Paper 001 presented at the 1962 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 12–13 April.
  32. Slaughter, E. Jr. 1962. Pitfalls of Pumping Unit Selection and Application. Paper 001 presented at the 1962 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 19–20 April.
  33. Byrd, J.P. 1989. Rating the Effectiveness of Beam and Sucker Rod Pumping Modes. Paper 021 presented at the 1989 Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  34. Lekia, S.D.L. and Day, J.J. 1988. An Improved Technique for the Evaluation of Performance Characteristics and Optimum Selection of Sucker-Rod Pumping Well Systems. Presented at the SPE Eastern Regional Meeting, Charleston, West Virginia, 1-4 November 1988. SPE-18548-MS. http://dx.doi.org/10.2118/18548-MS
  35. Juch, A.H. and Watson, R.J. 1969. New Concepts in Sucker-Rod Pump Design. J Pet Technol 21 (3): 342-354. SPE-2172-PA. http://dx.doi.org/10.2118/2172-PA
  36. Lietzow, C.H. 1956. The Long Stroke Hydraulic Pumping Unit. Paper 008 presented at the 1956 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 15–16 April.
  37. Joy, R.F. 1969. Flexible Pumping Strand. Paper 011 presented at the 1969 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  38. Lietzow, C.H. Hydraulic Pumping—New Developments. Paper 035 presented at the 1957 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 17–18 April.
  39. Metters, E.W. 1970. A New Concept in Pumping Unit Technology. Presented at the SPE Hobbs Petroleum Technology Symposium, Hobbs, New Mexico, SPE-3193-MS. http://dx.doi.org/10.2118/3193-MS
  40. Ewing, R.D. 1970. Long Stroke Pumping Unit. Presented at the SPE California Regional Meeting, Santa Barbara, California, SPE-3186-MS. http://dx.doi.org/10.2118/3186-MS
  41. Nickell, R.L. 1973. Dewatering Gas Wells with Pneumatic Pumping Equipment. Paper 18 presented at the 1973 Southwestern Petroleum Short Course, Lubbock, Texas, 26–27 April.
  42. Smith, L.A. 1975. Sucker Rod Pumping with Pneumatic Surface Units. Paper 033 presented at the 1975 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  43. Brinlee, L.D. 1979. Operating Experience with the Alpha I Pumping Unit: A New Alternative in Artificial Lift. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 23-26 September 1979. SPE-8240-MS. http://dx.doi.org/10.2118/8240-MS
  44. Hollenbeck, A.L. 1980. An Alternate Approach to High Volume, A Long Stroke Pumper. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 21-24 September 1980. SPE-9216-MS. http://dx.doi.org/10.2118/9216-MS
  45. Jesperson, P.J., Laidlaw, R.N., and Scott, R.J. 1981. The HEP (Hydraulic, Electronic, Pneumatic) Pumping Unit: Performance Characteristics, Potential Applications, and Field Trial Results. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October 1981. SPE-10250-MS. http://dx.doi.org/10.2118/10250-MS
  46. Mourlevat, J.J. and Morrow, T.B. 1982. Recently Developed Long Stroke Pumping Unit Incorporates Novel Flexibility for a Wide Variety of Applications. Presented at the SPE Production Technology Symposium, Hobbs, New Mexico, 8-9 November 1982. SPE-11338-MS. http://dx.doi.org/10.2118/11338-MS
  47. Tart, H.C. 1983. Operating and Performing Experience with Computer Controlled Long Stroke Rod Pumping Systems. Paper 29 presented at the 1983 Southwestern Petroleum Short Course, Lubbock, Texas, 27–28 April.
  48. Pickford, K.H. and Morris, B.J. 1989. Hydraulic Rod-Pumping Units in Offshore Artificial-Lift Applications. SPE Prod Eng 4 (2): 131-134. SPE-16922-PA. http://dx.doi.org/10.2118/16922-PA
  49. Hicks, A.W. and Jackson, A. 1991. Improved Design for Slow Long Stroke Pumping Units. Paper 22 presented at the 1991 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  50. Adair, R.L. and Dillingham, D.C. 1995. Ultra Long Stroke Pumping System Reduces Mechanical Failures, Lowers Lifting Cost While Increasing Production. Paper 001 presented at the 1995 Southwestern Petroleum Short Course, Lubbock, Texas, 14–15 April.
  51. Zhou, Z., Hu, C., Song, K. et al. 2000. Hydraulic Pumping Units for Offshore Platform. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16-18 October 2000. SPE-64507-MS. http://dx.doi.org/10.2118/64507-MS
  52. McCannell, D. and Holden, D.R. 2001. Long Stroke Pumping Systems in Deep Well Applications—Field Study. Presented at the SPE Western Regional Meeting, Bakersfield, California, 26–30 March. SPE-68791-MS. http://dx.doi.org/10.2118/68791-MS.
  53. McCoy, J.N., Podio, A.L., and Rowlan, L. 2001. Rotaflex Efficiency and Balancing. Presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 24–27 March. SPE-67275-MS. http://dx.doi.org/10.2118/67275-MS.
  54. Leitzow, C.H. 1984. Care and Maintenance of Long Stroke Hydraulic Pumping Units. Paper 020 presented at the 1984 Southwestern Petroleum Short Course, Lubbock, Texas, 24–26 April.
  55. McLane, C. Jr. 1954. Operation, Care and Maintenance of Pumping Units. Paper 010 presented at the 1954 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 13–14 April.
  56. Richards, C. 1955. Maintenance of Beam Type Pumping Units. Paper 020 presented at the 1955 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 14–15 April.
  57. Amerman, J. 1952. Foundation and Installation of Beam Type Pumping Units. Paper 032 presented at the 1952 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 13–14 April.
  58. Van Sant, R.W. Jr. 1954. Pumping Unit Lubrication. Paper 018 presented at the 1954 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 13–14 April.
  59. Pickens, J. 1957. Operation, Care and Maintenance of Beam Pumping Units. Paper 013 presented at the 1957 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 11–12 April.
  60. Amerman, J. 1958. Causes and Curse of Pumping Unit Reducer Troubles. Paper 006 presented at the 1958 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 17–18 April.
  61. Griffin, F. 1959. Installation and Care of Pumping Units. Paper 24 presented at the 1959 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 23–24 April.
  62. Elliot, B. 1962. Effect of Abuse and Misapplication of Pumping Unit Gears. Paper 02 presented at the 1962 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 12–13 April.
  63. Bullard, B.D. 1976. Preventative Maintenance for Beam Pumping Equipment. Paper 32 presented at the 1976 Southwestern Petroleum Short Course, Lubbock, Texas 22–23 April.
  64. Griffin, F.D. 1977. Maintenance of Pumping Units. Paper 022 presented at the 1977 Southwestern Petroleum Short Course, Lubbock, Texas, 21–22 April.
  65. Miceli, L.D. and Huff, M.D. 1988. Pumping Unit Preventative Maintenance. Paper 024 presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  66. API RP 11G, Recommended Practices for Installation and Lubrication of Pumping Units, fourth edition. 1994. Washington, DC: API.
  67. API RP 11ER, Recommended Practices for Guarding of Pumping Units, second edition. 1990. Washington, DC: API.

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See also

Sucker-rod lift

PEH:Sucker-Rod Lift