Gas Lift Design Philosophy Gas Lift Design Philosophy for Subsea Developmentsfor Subsea Developments

2001 European Gas Lift Workshop

(SUBSEA WELL DESIGN PHILOSOPHY)

WELL INTERVENTION

The Challenge...The Challenge...

““Size the downhole orifice as big as Size the downhole orifice as big as possible and we can just control the possible and we can just control the gas injection rates from the FPSO”gas injection rates from the FPSO”

- general comments heard from various engineers- general comments heard from various engineers

THE DOWNHOLE CHOKE (aka orifice) CONTROLS THE RATE OF GAS

INJECTION INTO THE TUBING, NOT THE SURFACE CHOKE!!!!!!!!

The Challenge..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 Predicting Stability Margins with Transient Margins with Transient

ProgramsProgramsOLGA is the primarily tool used within the OLGA is the primarily tool used within the industry for transient analysis, however it industry for transient analysis, however it “traditionally” does not look at transient “traditionally” does not look at transient

behavior between the surface and downhole behavior between the surface and downhole injection chokes. DynaLift addresses the gas injection chokes. DynaLift addresses the gas lift transient issue, but does a poor job of the lift transient issue, but does a poor job of the

flowline assessment. Hence, historically flowline assessment. Hence, historically ChevronTexaco had to use both programs…. ChevronTexaco had to use both programs….

Flowline/ Riser stability OLGAFlowline/ Riser stability OLGA

Gas Lift stability DynaLiftGas Lift stability DynaLift

Kuito Subsea Development, Kuito Subsea Development, Offshore AngolaOffshore Angola

Phase 1A: 12 producers, 1 gas Phase 1A: 12 producers, 1 gas injector: injector:

• Placed on production Jan 2000Placed on production Jan 2000

Phase 1B: 6 water injectorsPhase 1B: 6 water injectors• completed by 2001completed by 2001

Phase 1C: 7 producers, 3 water Phase 1C: 7 producers, 3 water injectors:injectors:

• Placed on production Oct 2001Placed on production Oct 2001ALL PRODUCERS COMPLETED WITH SINGLE POINT LIFT GAS INJECTION

Kuito 1A

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 …..

Graph 2 - Base case with 2 valves at 500 psi wellhead pressure

0

500

1000

1500

2000

2500

3000

0 500 1000 1500 2000 2500

Elapsed time (minutes)

Gas

th

rou

gh

val

ve (

Msc

fd)

upper valve (0.3125) lower valve (1")

UPPER “OPERATING”

ORIFICE

LOWER “UNLOADING” ORIFICE

WHY THIS IDEA WILL NOT WORK ….

Kuito Phase 1A UpdateKuito Phase 1A Update Serious Problems with Flowline Stability Serious Problems with Flowline Stability

(slugging in risers).(slugging in risers).

Test lines sized too large in that Test lines sized too large in that

additional gas is needed during the additional gas is needed during the

testing of the well for flowline stability.testing of the well for flowline stability.

Original designs only valid for watercuts Original designs only valid for watercuts

up to 50%. Within one year, one well up to 50%. Within one year, one well

reached 75% w/c.reached 75% w/c.HOW DID WE LEARN FROM THIS FOR THE PHASE 1C COMPLETIONS?

Kuito Phase 1C StudyKuito Phase 1C Study Completed downhole transient work Completed downhole transient work

simultaneously as the flowing transient simultaneously as the flowing transient study. Looked at minimum required study. Looked at minimum required gas rates for both and based operating gas rates for both and based operating points on the lowest value (whether it points on the lowest value (whether it was dictated by the riser or gas lift was dictated by the riser or gas lift system).system).

Evaluated watercuts up to 95%.Evaluated watercuts up to 95%.

OTHER SUBSEA GAS LIFT ISSUES

Surface Controlled Gas Surface Controlled Gas lift Valveslift Valves

ProsPros– eliminates need for extensive orifice sizingeliminates need for extensive orifice sizing– reduces risk of erosion. Can remain “full open” reduces risk of erosion. Can remain “full open”

during unloading and then close to necessary during unloading and then close to necessary orifice size.orifice size.

– Orifice size can change as well conditions Orifice size can change as well conditions change without an intervention.change without an intervention.

ConsCons– expensive expensive (to date, ChevronTexaco has been unable to (to date, ChevronTexaco has been unable to

justify the cost of this system for its existing justify the cost of this system for its existing developments)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 The only valid flow correlation for tubing sizes larger than 5.5” is OLGA. OLGA is sizes larger than 5.5” is OLGA. OLGA is not available in the transient program.not available in the transient program.

Reverse flow gas lift: program is not Reverse flow gas lift: program is not configured for annular flow and hence configured for annular flow and hence cannot calculate the increased friction loss cannot calculate the increased friction loss found in this type of completion.found in this type of completion.

What are we doing about this?What are we doing about this?

We are working with SCANDPOWER Inc. to We are working with SCANDPOWER Inc. to configure OLGA to properly assess single point configure OLGA to properly assess single point gas lift systems. The results will be “checked” gas lift systems. The results will be “checked”

against that calculated via Dynalift. If against that calculated via Dynalift. If successful, we will use OLGA primarily for the successful, we will use OLGA primarily for the

larger pipe and / or deviated completions. larger pipe and / or deviated completions.

Future goals include incorporating the VPC data Future goals include incorporating the VPC data into OLGA and configuring the program to into OLGA and configuring the program to

handle multi-valve gas lift completions.handle multi-valve gas lift completions.

Single Point Injection is not Single Point Injection is not just for Subsea ….just for Subsea ….

If the injection pressure is available for a single point system, why use unloading

valves?

QUESTIONSQUESTIONS

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