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

Presentation Outline Single Point Injection (pros and cons) Single Point Injection (pros and cons) Understanding the Stability Issues Understanding the Stability Issues Using Transient Programs Using Transient Programs Field example Field example Other Subsea Gas Lift Issues Other Subsea Gas Lift Issues Questions Questions

(SUBSEA WELL DESIGN PHILOSOPHY) WELL INTERVENTION

Single Point Injection Using Orifice Pros Pros higher reliability than conventional completion using live valveshigher reliability than conventional completion using live valves meets “zero intervention” philosophy set for subsea developmentsmeets “zero intervention” philosophy set for subsea developments Cons Cons requires a minimum gas injection rate for well stabilityrequires a minimum gas injection rate for well stability requires a higher injection pressurerequires a higher injection pressure valve erosion becomes an issuevalve erosion becomes an issue

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!!!!!!!!

Gas Lift Stability For a single point system, there is a minimum surface injection rate required for the orifice to maintain sufficient annular backpressure (i.e. casing pressure consistently higher than the flowing tubing pressure) for continuous downhole gas injection.

Minimum Injection Rates This minimum injection rate is a function of orifice size and flowing tubing pressure (aka wellhead pressure, PI, reservoir pressure, watercut, etc) What does happen at rates lower than this minimum injection rate?

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.

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

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

Kuito 1A

Objectives of Original Gas Lift Study Determine orifice size that will allow for stable production between MMscfd for the 10 year life of the well Determine orifice size that will allow for stable production between MMscfd for the 10 year life of the well Recommend injection gas rates to minimize erosion and provide approximate time / procedures to unload the well. Recommend injection gas rates to minimize erosion and provide approximate time / procedures to unload the well. How will flowline slugging affect well stability? How will flowline slugging affect well stability? - information first presented at the 2000 Offshore Technology Conference, paper #11874

Field Parameters for Original Study

unstable

Simulation: Injection Rate vs Watercut

Effect of Fluctuating Wellhead Pressure unstable

U-tube effect

“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 THE CHALLENGE …..

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

Kuito Phase 1A Update Serious Problems with Flowline Stability (slugging in risers). 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. 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. 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?

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). 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%. Evaluated watercuts up to 95%.

OTHER SUBSEA GAS LIFT ISSUES

Surface Controlled Gas lift Valves Pros 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 Cons –expensive (to date, ChevronTexaco has been unable to justify the cost of this system for its existing developments)

: 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. 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. 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.

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. 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. Future goals include incorporating the VPC data into OLGA and configuring the program to handle multi-valve gas lift completions.

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

QUESTIONS ? ? ? ? ? ?