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Gas Lift Design Philosophy for Subsea Developments

This article discusses the challenges and solutions in gas lift design for subsea wells, including the control of gas injection rates, stability issues, transient behavior, flowline and riser stability, and the use of surface-controlled gas lift valves. The limitations of existing programs and future goals for improvement are also mentioned.

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Gas Lift Design Philosophy for Subsea Developments

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  1. Gas Lift Design Philosophy for Subsea Developments 2001 European Gas Lift Workshop

  2. WELL INTERVENTION (SUBSEA WELL DESIGN PHILOSOPHY)

  3. The Challenge... “Size the downhole orifice as big as possible and we can just control the gas injection rates from the FPSO” - general comments heard from various engineers • THE DOWNHOLE CHOKE (aka orifice) CONTROLS THE RATE OF GAS INJECTION INTO THE TUBING, NOT THE SURFACE CHOKE!!!!!!!!

  4. The Challenge.. “If this stability issue exists, then how come I don’t see this with my platform wells?” - general comments from various engineers Answer: Turns out they are not continuously injecting through the orifice. As these platform wells are completed with a conventional design (unloading valves), the well instability is dampened due to multipointing.

  5. Predicting Stability Margins with Transient Programs OLGA is the primarily tool used within the industry for transient analysis, however it “traditionally” does not look at transient behavior between the surface and downhole injection chokes. DynaLift addresses the gas lift transient issue, but does a poor job of the flowline assessment. Hence, historically ChevronTexaco had to use both programs…. Flowline/ Riser stability OLGA Gas Lift stability DynaLift

  6. Kuito Subsea Development, Offshore Angola • Phase 1A: 12 producers, 1 gas injector: • Placed on production Jan 2000 • Phase 1B: 6 water injectors • completed by 2001 • Phase 1C: 7 producers, 3 water injectors: • Placed on production Oct 2001 ALL PRODUCERS COMPLETED WITH SINGLE POINT LIFT GAS INJECTION

  7. Kuito 1A

  8. unstable

  9. U-tube effect

  10. THE CHALLENGE ….. “In order to prevent erosion to the orifice, let’s run two of them. Have the upper orifice the “operating point” and then run a REALLY large unloading orifice below it!” - comments made by the reservoir engineering staff working on the project

  11. LOWER “UNLOADING” ORIFICE UPPER “OPERATING” ORIFICE WHY THIS IDEA WILL NOT WORK ….

  12. Kuito Phase 1A Update • Serious Problems with Flowline Stability (slugging in risers). • Test lines sized too large in that additional gas is needed during the testing of the well for flowline stability. • Original designs only valid for watercuts up to 50%. Within one year, one well reached 75% w/c. HOW DID WE LEARN FROM THIS FOR THE PHASE 1C COMPLETIONS?

  13. Kuito Phase 1C Study • Completed downhole transient work simultaneously as the flowing transient study. Looked at minimum required gas rates for both and based operating points on the lowest value (whether it was dictated by the riser or gas lift system). • Evaluated watercuts up to 95%.

  14. OTHER SUBSEA GAS LIFT ISSUES

  15. Surface Controlled Gas lift Valves • Pros • eliminates need for extensive orifice sizing • reduces risk of erosion. Can remain “full open” during unloading and then close to necessary orifice size. • Orifice size can change as well conditions change without an intervention. • Cons • expensive (to date, ChevronTexaco has been unable to justify the cost of this system for its existing developments)

  16. We are having difficulty using the gas lift transient program for other subsea/offshore developments because of the following limitations: • The only valid flow correlation for tubing sizes larger than 5.5” is OLGA. OLGA is not available in the transient program. • Reverse flow gas lift: program is not configured for annular flow and hence cannot calculate the increased friction loss found in this type of completion.

  17. What are we doing about this? We are working with SCANDPOWER Inc. to configure OLGA to properly assess single point gas lift systems. The results will be “checked” against that calculated via Dynalift. If successful, we will use OLGA primarily for the larger pipe and / or deviated completions. Future goals include incorporating the VPC data into OLGA and configuring the program to handle multi-valve gas lift completions.

  18. Single Point Injection is not just for Subsea ….If the injection pressure is available for a single point system, why use unloading valves?

  19. QUESTIONS ? ? ? ? ? ?

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