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By M. Ghareeb (Lufkin Middle East) Luca Ponteggia (Agip, Italy)

Beam Pumping System Efficiency Improvement in Agiba’s Western Desert Fields. By M. Ghareeb (Lufkin Middle East) Luca Ponteggia (Agip, Italy) K. F. Nagea (Agiba Petroleum company). M E D I T E R R A N E A N S E A. MATRUH. ALEX. EL HAMRA. MELEIHA. CAIRO. ZARIF. W. RAZZAK.

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By M. Ghareeb (Lufkin Middle East) Luca Ponteggia (Agip, Italy)

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  1. Beam Pumping System Efficiency Improvement in Agiba’s Western Desert Fields By M. Ghareeb (Lufkin Middle East) Luca Ponteggia (Agip, Italy) K. F. Nagea (Agiba Petroleum company)

  2. M E D I T E R R A N E A N S E A MATRUH ALEX. EL HAMRA MELEIHA CAIRO ZARIF W. RAZZAK EL FARAS S I N A I RAML & R. SW FARAS SE G U L F O F S U E Z W E S T E R N D E S E R T GULF OF AQABA 0 100 km. RED SEA ASHRAFI AGIBA OPERATING AREAS

  3. Production History of Western Desert Fields

  4. W.D. Artificial Lift Systems

  5. Initial Reservoir Data and Fluid Properties For Meleiha Fields

  6. 36,500 lbs structure rating 66% loaded 912,000 in-lbs reducer rating 61.5% loaded 75 hp Electrical ultra high slip motor 48% loaded 3.5” Tubing 86- H T S (N97) sucker rods 60.3% loaded 30-250-RWBC- 24- 4 2.75” seating nipple at +/- 5000 ft Tubing anchor catcher Target production +/- 1000 BPD / well

  7. Average Static Reservoir Pressure Two Years Later What Was Happening?

  8. Very Low Equipment Running Lives • Upper part of the 7/8” and in the 3/4 “string. • Fatigue failure plus unscrewed couplings • Rod parting • Down hole pump problems • Unscrewed and leaking valves • Pump stuck

  9. 1988, Failures Distribution

  10. The Main Factors Affecting the Equipment Performances • Fast decline in reservoir pressure • Limitations of subsurface pump design • Down hole pumps were bottom hold-down type • One size of D.H.P. restricted the flexibility • Lack of experience with sucker rod system • Mishandling of high tensile type rods • Weak monitoring system

  11. Where we were in 1993?

  12. Failure Analyses • Failures are divided into four major categories : • Sucker Rod and polished rod failures • Down hole pump failures • Tubing wear • Surface Pumping Unit failures

  13. Sucker Rod Failures All sucker rod, pony rod, and coupling failures are either • Tensile failures (applied load exceeds the tensile strength of the rod ) or • Fatigue Failures Fatigue Failures

  14. Common Rod Failure Causes • Mishandling • Gas or fluid pound • Design problem • Wear or rubbing on tubing • Corrosion • Operating problems

  15. Mishandling • Improper handling during pulling and running • Tools • Pull rod in double and lay down on racks • Improper coupling make-up • Low experience of pulling unit crew

  16. Down Hole Pump Failure • Stuck Pump • Traveling and standing valves damage (unscrew).

  17. Standing Valve • Unscrew

  18. Common Tubing Failure Causes • Mutual friction between sucker rod coupling and tubing inner surface • Tubing and/or sucker rod buckling • Using 1” sucker rods as a sinker bar with full size 2 3/16” coupling • The high water cut wells creates less lubrication and cooling between sucker rod and tubing

  19. Coupling wear Due to tubing Movement

  20. Corrective Action • Reservoir support and water shut off • Acquire appropriate data and determine true cause of failure • Sucker rods • Downhole Pumps • Tubing wear • Gas Interference

  21. Reservoir Support by Water Injection Water Injection

  22. Determining Reason For Failures • Perform failure analysis • Track failure occurrences • Execute corrective action

  23. Sucker Rod Handling • Pull the rods in stands and hang in the derrick • Use sucker rod power tong • Transport sucker rods in special sucker rod baskets • Pulled sucker rods are fully inspected and stored as per API standards • Translate the API standard procedures for rod handling to Arabic and train all relevant personnel

  24. Downhole Pumps • Used top hold-down Pump 30-250 RWAC 24-4 30-225 RHAC 24-4-2 30-200 RWAC 24-4 30-175 RHAC 24-4-2 • Introduced different sizes of subsurface pumps • Upgrade pump materials

  25. Modified the Insert pump Anchor

  26. Where are we Today?

  27. Service contract for Dynamometer and fluid level Pilot test for well controller Well Monitoring

  28. Well Head Temperature As A Relation Of Production Rate (GOR From Zero Up To 100 Scf/Stb)

  29. Beam Unit Maintenance by specialized crew The Future Plan?

  30. Install Well Controller

  31. Conclusions • As fields mature alternate solutions must be determined • Acquire appropriate data to determine true reason for failures • Continuous monitoring • Flexible operating design

  32. Applicable Solutions • Proper handling techniques • Top-hold-down pumps • Reduce gas and fluid pounding • Seat pumps below perforations • Tubing anchors >3000’ • Appropriate packer selection • Sinker bars

  33. Team work and sharing of technology is the key of success for any improvement

  34. Beam Pumping System Efficiency Improvement in Agiba Western Desert Fields By M. Ghareeb (Lufkin Middle East) Luca Ponteggia (Agiba Petroleum company) K. F. Nagea (Agiba Petroleum company)

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