Gaslift as Back-Up for a Subsea ESP Lifted

Well

Philip Holweg - Shell Expro

Eric Lovie - Schlumberger

API Gaslift WorkshopWoodbank, Aberdeen

12 November 2001

Gaslift as Back-Up for a Subsea ESP Lifted Well

Outline• Justification for installing gaslift on an ESP

lifted well• Gaslift orifice selection• ESP and gaslift performance to date

Introduction to Gannet E

Reservoir characteristics • API = 20.8• Viscosity = 12 cP• GOR = 113 scf/bbl• Reservoir pressure = 2,400 psi• Reservoir depth = 5,700 ft • Strong aquifer support• High permeability sands 1 - 2 Darcy

Gannet E - Subsea ESP Development

Justification for ESP & Gaslift

• Reservoir fluids very heavy and viscous• Well productivity proved to be high (58

bbl/day/psi)– confirmed by dedicated well test before ESP was

designed

• High flowline backpressure– 1,200 psi with 2 ESPs flowing

• Expected flow rates:– Natural 0 – Gaslift 1x 6,000 bbl/day– ESP 3x 18,000 bbl/day

• Therefore ESP is preferred artificial lift method

Justification for ESP & Gaslift

• Uncertainty around ESP runlife– one of the first subsea ESP installations worldwide– require at least 6 - 12 months runlife to break even

due tohigh ESP change-out cost subsea

• Infrastructure synergy with GF– only needed 7 km additional gaslift line

• Therefore, a dedicated gaslift line was justified to GE– minimises economic exposure in case of ESP failure

Benefits of Gaslift Back-Up

• Production optimisation – minimise oil deferment upon ESP failure– scheduling time for workover rig is 4 - 12 weeks

• Maximising value– later in field life it is more economic to gaslift than

to perform ESP change-out– Cost of ESP change-out (4 - 5 M£)

Gaslift Valve Selection

Gaslift has to be compatible with ESP lift

• Main objective is to protect ESP cable– prevent gas migration into ESP cable elastomers

(risk of explosive decompression of cable)– allow bleed-off of annulus in a controlled manner

(maintain <5 bar above THP)– ensure annulus fluid does not change

(control pressure fluctuations due to unwanted fluid effects)

• Therefore annulus requires to be a closed volume– install a draw bar in gaslift valve– employ a single point injection system

ESP system

3,000 ft Sand Screens

4-1/2” Side Pocket Mandrel @ 4,400 ft TVSS

5-1/2” Tubing

10-3/4” ESP Packer

Gannet E - Completion Diagramme

Draw Bar(shear pressure 1,000 psi)

Gaslift Valve with Draw Bar

0

10,000

20,000

18:00 00:00 06:00 12:00 18:00 00:00 06:00

Flo

w (

bb

l/d

) 40

90

140

Tem

p (

F) 0

Time (hours)

500

1,000

1,500

2,000

2,500

Pre

ssu

re (

Psi)

gaslift

PDG

annulus

THP

riser

separator

THT

separator gross

Well unloaded

Draw bar shear

Export line unloading

1,000 psi(gradientcorrected)

Drawdown

Well unloading

Startpressurising

annulus

Gaslift Activation

0

5,000

10,000

15,000

20,000

25,000

Jan-98 Apr-98 Jul-98 Oct-98 Jan-99 Apr-99 Jul-99 Oct-99 Jan-00

Rate

(b

bl/

d)

WaterOil

ESP #1 ESP #2

Waterbreakthrough

ESP #1failure

Gaslift

ESP vs Gaslift Performance #1

0

5,000

10,000

15,000

20,000

25,000

Feb-00 May-00 Aug-00 Nov-00 Feb-01 May-01 Aug-01 Nov-01

Rate

(b

bl/

d)

WaterOil

ESPfrequencyincrease ESP #2

failure

Gaslift

ESP #2

ESP vs Gaslift Performance #2

Gaslift and ESP Production Rates

• GE-01 Production performance to date– ESP #1: 17 months runlife @ 15,000 - 18,000

bbl/day– Gaslift: 2 months @ 5,000 - 8,000 bbl/day– ESP #2: 23 months runlife @ 15,000 - 18,000

bbl/day– Gaslift: 4 months @ 5,000 - 6,000 bbl/day

• More gaslift at higher watercut & tail end production– less priority to work over well - availability of mobile rig– well will be put on gaslift permanently end of field– workover costs 4 M £ - 5 M£

Conclusions

• Business case:– good insurance on development risk– reduces oil deferment in case of ESP failure– optimises tail-end of field life economics

• Performance:– valve operation demonstrated– ESP versus gaslift rates as predicted