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Operation of sucker-rod lift systems

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Ongoing operation of a sucker-rod lift system may involve a certain amount of automation and control. Information on troubleshooting problems is also discussed.

Automation and pumping control

Automation means different things to different people and becomes a problem when the term triggers concern from the field about personnel reduction. Thus, sucker-rod-lift automation may not always be considered good if not properly applied. However, there needs to be monitoring and control equipment on an installation to enhance:

  • Proper operation
  • Monitoring
  • Failure reduction or prevention
  • Troubleshooting/problem solving

At minimum, a sucker-rod-lift installation should have vibration switches on the unit to shut it down, if there is a high part in the rod string that will cause overloading of the gearbox or damage to the unit foundation. There should be a pressure gauge (or a connection for a pressure gauge to allow temporary installation) on the flowline-pumping T, downstream of the check valve that monitors the flowline pressure. There should also be some type of pump-cycle controller. This may be from a simple time clock to a more sophisticated pumpoff or rod-pump controller.

A number of papers have been published that address automation of sucker-rod-lift or beam-pump automation and control. [1][2][3][4][5][6][7][8][9][10][11][12][13][14] There is also a reference on practical automation for mature fields. [15] If a high degree of automation is considered, then a very important side consideration is keeping this electrical equipment working, especially during electrical storms; thus, proper lightning protection and grounding should be considered. [16][17][18][19]

A study made several years ago indicated that at least one-half of the pumping wells surveyed had a subsurface pump installed that was too large (Conoco unpublished internal report). The results of such installations were devastating fluid pounds when wells were overpumped, resulting in short run times and increased failure frequency. Because of the cost to pull and replace a pump, typically other parts of the sucker-rod-lift system were changed to compensate for the oversized pump. Too many times, the too-large pump is a result of habit or of not optimizing when the well capacity has changed.

It is still possible to live with the too-large pump until the correct size can be installed. Some interim measures are to reduce the pump displacement by reducing the strokes per minute, shortening the stroke, and decreasing backpressure on the tubing/casing annulus, thereby decreasing formation backpressure, allowing more fluid inflow, and reducing the pumping time.

Probably the most common type of well control or automation is time clocking, which consists of pumping a portion of a 15-minute period. Percentage timers and pumpoff controls are used in modern time-clocking work. The purpose of time clocking is to adjust the pump capacity to the well capacity.

Pumpoff controllers have been developed over the years to:

  • Be standalone monitors
  • Provide rod-string load and polished-rod position and related dynamometer cards
  • Be installed with communication links to allow remote monitoring and control of the installation

Current advancements in computers along with electrical end devices allow sophisticated control of individual installations and/or a whole field. If new pumping installations are planned, these types of controllers/automation should be considered. It becomes more difficult to justify a retrofit to a long-time producing field, but this may be considered depending on access to the field, variable well inflow, and/or reduction in operating costs by reducing well failures. Many papers on pumpoff or rod-pump controllers, different theories concerning their operation, and controller installation and operation have been published. [20][21][22][23][24][25][26][27][28][29][30][31] These should be reviewed to determine if or when a controller may be advantageous to install.

Troubleshooting

Once a sucker-rod-lift system is installed on a well, the continued monitoring and optimization of pumping parameters begins. Obtaining monthly well tests on the fluid production from the well and a fluid/pump submergence level is recommended to ensure that the well capacity is within the recommended pump-capacity range, the well does not have excess capacity or equipment needs to be changed because of excessively high fluid levels, and that excessive pumping of the well is not occurring.

Although current rod-string-design models, simulators, and programs are fairly accurate, they still need individual-well calibration to ensure that the design assumptions are correct for the actual well conditions. Additionally, to know what is different and why, the six main well loads need to be recorded from the predictive design. These loads need to be compared to the actual well loads with known fluid-level, well-test, and pumping parameters. Gipson and Swaim [32] have described these six basic loads and their relationship to a surface dynamometer card.

Many papers have been published on dynamometers and their use on sucker-rod-lifted wells. [33][34][35][36][37][38][39][40][41][42] Some of these provide discussion of surface loads and surface dynamometer cards, while the latest trend is to discuss downhole dynamometer cards (or pump cards). While obtaining actual downhole loads that these dynagraphs recorded, there has been recent work on developing and field-testing a downhole dynamometer. [43][44][45]

While these measurements investigate the sucker-rod-string loads, the other components of the lift system also should be investigated, including the pumping unit and gearbox. As previously discussed, there are only two techniques to check if a pumping unit is overloaded[46]: conducting a torque analysis or comparing the permissible-load diagram (PLD) for the pumping unit to the loads from the surface dynamometer card. The torque-analysis technique has been demonstrated by Gipson and Swaim, [47] and Takacs, [48] Gault, [49] and Teel[50] have discussed PLDs or envelopes. Chastain discussed examples of PLD use for properly counterbalancing a pumping unit. [51]

Failures of sucker-rod-lift components have been discussed in countless papers. The use of current data processing and root-cause analysis of these failures has been the recent industry trend to assist in reducing failures. [52],[53] Additionally, the Artificial Lift Energy Optimization Consortium (ALEOC) program in west Texas has been useful for operators to compare the failure frequency of their sucker-rod-lift components, wells, and fields with other operators to find areas of improvement. [54] One final new trend developing for this lift method is a total well-management concept that integrates the well capacity/pump submergence and rod-string and pumping-unit loads with power demands. This may prove the best practice for optimizing, troubleshooting, and reducing failures along with reducing associated lifting costs.

References

  1. ↑ Shore, R.A. 1972. The Kern River SCAN Automation System - Sample, Control and Alarm Network. Presented at the SPE California Regional Meeting, Bakersfield, California, 8-10 November 1972. SPE-4173-MS. http://dx.doi.org/10.2118/4173-MS
  2. ↑ Wadlington, W.H. 1973. How Amoco Approached Automation in West Texas. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Las Vegas, Nevada, 30 September-3 October 1973. SPE-4684-MS. http://dx.doi.org/10.2118/4684-MS
  3. ↑ Egan, J.D. 1976. Oil Field Automotive—Ten Years’ Experience. Paper 041 presented at the 1976 Southwestern Petroleum Short Course, Lubbock, Texas, 22–23 April.
  4. ↑ Irby, R.E. 1977. Wellsite Management and Control of Rod Pumped Wells. Paper 023 presented at the 1977 Southwestern Petroleum Short Course, Lubbock, Texas, 21–22 April.
  5. ↑ Jentsch Jr., W.A. and Marrs, R.D. 1988. Computerized Automation of Oilfield Production Operations: An Extensive 5-Year Study Into the Costs and Benefits. SPE Prod Eng 3 (3): 299-304. SPE-15392-PA. http://dx.doi.org/10.2118/15392-PA
  6. ↑ Svinos, J.G. 1990. Application of Expert System Technology to the Design of Rod Pumping Systems. Paper 033 presented at the 1990 Southwestern Petroleum Short Course, Lubbock, Texas, 18–19 April.
  7. ↑ Luppens, J.C. 1995. Practical Automation for Mature Producing Areas. SPE Comp App 7 (2): 44-48. SPE-26591-PA. http://dx.doi.org/10.2118/26591-PA
  8. ↑ Outomuro, M.V. 1995. Using Automation for Optimizing Production Fields. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 2-4 April 1995. SPE-29534-MS. http://dx.doi.org/10.2118/29534-MS
  9. ↑ Findley, C.P. II, Herring, R.B., and Pike, J.S. 1996. Automation in Cyclical Rate Primary Reservoirs Significantly Reduces Beam Pumping Failures. Paper 012 presented at the 1996 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  10. ↑ Westerman, G.W. 1997. Automated Well Head Management. Paper 034 presented at the 1997 Southwestern Petroleum Short Course, Lubbock, Texas, 2–3 April.
  11. ↑ Ray, L. 1998. Using Integrated Software for Fall Field Automation and Analysis. Paper 016 presented at the 1998 Southwestern Petroleum Short Course, Lubbock, Texas, 8–9 April.
  12. ↑ Vazquez, M. and Fernandes, J. 1999. Rod-Pumping Optimization Through Surface and Downhole Parameter Estimation and Simulation. Presented at the SPE Mid-Continent Operations Symposium, Oklahoma City, Oklahoma, 28-31 March 1999. SPE-52214-MS. http://dx.doi.org/10.2118/52214-MS
  13. ↑ Fernandes, J. and Lastra, A. 2001. Experiences on Heavy and Extra-Heavy Crude Rod Pumping Automation Applications using Thermal and Dilution Techniques. Presented at the SPE International Thermal Operations and Heavy Oil Symposium, Porlamar, Margarita Island, Venezuela, 12-14 March 2001. SPE-69900-MS. http://dx.doi.org/10.2118/69900-MS
  14. ↑ Sengul, M. and Bekkousha, M.A. 2002. Applied Production Optimization: i-Field. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October 2002. SPE-77608-MS. http://dx.doi.org/10.2118/77608-MS
  15. ↑ Cerqueira, J.F. et al.: “Development of an Intelligent Distributed Management System for Automated Wells (SPGA),” paper SPE 77609 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September–2 October.
  16. ↑ Howell, J.K. and Hogwood, E.E. 1981. Electrified Oil Production. Tulsa, Oklahoma: PennWell Books.
  17. ↑ Brinner, T.R. and Atkins, J.D. 2002. Oilfield Grounding. Paper 44 presented at the 2002 Southwestern Petroleum Short Course, Lubbock, Texas, 24–25 April.
  18. ↑ Skinner, D.R. 1977. Lightning Protection for an Oilfield Automation And Instrumentation System. J Pet Technol 29 (11): 1405-1409. SPE-6386-PA. http://dx.doi.org/10.2118/6386-PA
  19. ↑ Lapis, T. 2002. Sucker-Rod Pumping Unit Lightning Protection. Paper 21 presented at the 2002 Southwestern Petroleum Short Course, Lubbock, Texas, 24–25 April.
  20. ↑ Hudgins, T.A. and McKee, F.E. 1975. Pump-Off Control—The Average Motor Current Method. Paper 032 presented at the 1975 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  21. ↑ Westerman, G.W. 1977. Successful Application of Pump-off Controllers. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6853-MS. http://dx.doi.org/10.2118/6853-MS
  22. ↑ Hunter, J.C., Hubbell, R.S., and Reiter, C.R. 1978. Denver Unit Well Surveillance and Pump-Off Control System. J Pet Technol 30 (9): 1319-1326. SPE-6849-PA. http://dx.doi.org/10.2118/6849-PA
  23. ↑ Neely, A.B. 1979. Computer Pump Off Control of Sucker Rod Pumped Wells—Denver Unit, Wasson Field, Gaines and Yoakum Counties, Texas. Paper 017 presented at the 1979 Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  24. ↑ Amezcua, J.D. 1980. Comparative Analysis of Pump-off Control Systems for Field Applications. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 21-24 September 1980. SPE-9362-MS. http://dx.doi.org/10.2118/9362-MS
  25. ↑ Neely, A.B. and Tolbert, H.O. 1988. Experience With Pumpoff Control in the Permian Basin. J Pet Technol 40 (5): 645-649. SPE-14345-PA. http://dx.doi.org/10.2118/14345-PA
  26. ↑ Guffey, C.G., Rogers, J.D., and Hester, L.R. 1989. Beam Pump Control Today. Paper 024 presented at the 1989 Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  27. ↑ Blackford, T.A., Dunn, J.R., and Joseok, R. 1991. Benefits of Improving Pump-Off Control for Beam Pumped Producing Wells. Paper 020 presented at the 1991 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  28. ↑ Eckel, A.C., Abels, H.P., and Merritt, R.A. 1995. Testing And Practically Applying Pump-Off Controllers In A Waterflood. Presented at the SPE Western Regional Meeting, Bakersfield, California, 8-10 March 1995. SPE-29636-MS. http://dx.doi.org/10.2118/29636-MS
  29. ↑ Gill, R.A., Soza, R.L., and Ott, R.E. 1997. Using Pump-Off Controllers (P.O.C.) to Their Fullest. Paper 007 presented at the 1997 Southwestern Petroleum Short Course, Lubbock, Texas, 2–3 April.
  30. ↑ Lindsay, A.B. 1998. Applying Pump Off Controllers to Marginal Producers. Paper 009 presented at the 1998 Southwestern Petroleum Short Course, Lubbock, Texas, 8–9 April.
  31. ↑ McCoy, J.N., Podio, A.L., and Becker, D. 1999. Timer Control of Beam Pump Run Time Reduces Operating Expenses. Paper 009 presented at the 1999 Southwestern Petroleum Short Course, Lubbock, Texas, 21–22 April.
  32. ↑ Gipson, F.W. and Swaim, H.W.: “The Beam Pumping Design Chain,” paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.
  33. ↑ Chastain, J. 1954. Diagnosis of Pumping Well Equipment Troubles by the Use of a Dynamometer. Paper 019 presented at the 1954 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 13–14 April.
  34. ↑ Fagg, L.W. 1956. Dynamometer Fundamentals as Applied to Water Flood Operations. Paper 035 presented at the 1956 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 15–16 April.
  35. ↑ Merryman, C.J. and Lawrence, D.L. 1958. Dynamometer Testing for Analyzing the Pumping Well Problem. Paper 041 presented at the 1958 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 17–18 April.
  36. ↑ Lawrence, D.L. and Merryman, C.J. 1959. Dynamometer Lease Studies. Paper 004 presented at the 1959 Annual West Texas Oil Lifting Short Course, Lubbock, Texas, 23–24 April.
  37. ↑ Slonneger, J.C. 1961. Dynagraph Analysis of Sucker Rod Pumping. Houston, Texas: Gulf Publishing.
  38. ↑ Gibbs, S.G. and Neely, A.B. 1966. Computer Diagnosis of Down-Hole Conditions In Sucker Rod Pumping Wells. J Pet Technol 18 (1): 91-98. SPE-1165-PA. http://dx.doi.org/10.2118/1165-PA
  39. ↑ Hudgins, T.A. 1981. Use and Applications of Dynamometer for Surface and Downhole Analysis. Paper 026 presented at the 1981 Southwestern Petroleum Short Course, Lubbock, Texas, 23–24 April.
  40. ↑ Houang, A.B. et al. 1991. Pattern Recognition Applied to Dynamometer Cards for Sucker Rod Diagnosis. Paper 023 presented at the 1991 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  41. ↑ McCoy, J.N., Jennings, J.W., and Podio, A.L. 1992. A Polished Rod Transducer for Quick and Easy Dynagraphs. Paper 003 presented at the 1992 Southwestern Petroleum Short Course, Lubbock, Texas, 22–23 April.
  42. ↑ Swaim, H.W. and Hein, N.W. Jr. 1987. Surface Dynamometer Card Interpretation: A Beam Pumping Problem Solving Tool. Presented at the 1987 Southwestern Petroleum Short Course, Lubbock, Texas, 22–23 April.
  43. ↑ Albert, C.D. 1994. Downhole Dynamometer Tool. Paper 001 presented at the 1994 Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  44. ↑ Soza, R.L. 1996. Review of Downhole Dynamometer Testing. Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 27-29 March 1996. SPE-35217-MS. http://dx.doi.org/10.2118/35217-MS
  45. ↑ Waggoner, J.R. and Mansure, A.J. 2000. Development of the Downhole Dynamometer Database. SPE Prod & Oper 15 (1): 3-5. SPE-60768-PA. http://dx.doi.org/10.2118/60768-PA
  46. ↑ 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
  47. ↑ Gipson, F.W. and Swaim, H.W. 1969. Beam Pumping Fundamentals. Presented at the 1969 Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  48. ↑ Takacs, G. 1989. Torque Analysis of Pumping Units Using Dynamometer Cards. Paper 028 presented at the 1989 Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  49. ↑ Gault, R.H. 1991. Envelopes for Pumping Units. Paper 017 presented at the 1991 Southwestern Petroleum Short Course, Lubbock, Texas, 21–22 April.
  50. ↑ Teel, L. 1991. Permissible Load Envelopes for Beam Pumping Units. Paper 029 presented at the 1991 Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  51. ↑ Chastain, J. 1976. Use of Lead/Lag to Reduce Torque on Pumping Units. Oil & Gas J. (October): 38.
  52. ↑ Junkins, E.D. Jr. 1971. Pumping Well Failure Analysis Using Electronic Data Processing Techniques. Paper 015 presented at the 1971 Southwestern Petroleum Short Course, Lubbock, Texas, 15–16 April.
  53. ↑ Gantz, K. and Disney, V. 1997. Guide to Well Failure Root Cause Analysis in Sour Beam Pumping Service. Paper 005 presented at the 1997 Southwestern Petroleum Short Course, Lubbock, Texas, 2–3 April.
  54. ↑ Rahman, M.M. and Heinze, L.R. 2000. Development of ALEOC Beam Pumping Failure Data Base. Paper 017 presented at the 2000 Southwestern Petroleum Short Course, Lubbock, Texas, 12–13 April.

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See also

Sucker-rod lift

Downhole sucker-rod pumps

Sucker-rod pumping units

Prime mover for sucker-rod pumping unit

PEH:Sucker-Rod_Lift

Page champions

John G. Svinos

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