Performance analysis of gas-lifted subsea wells from combined well tests

by

Wim der Kinderen

Consultant Production Technologist

Shell UK Exploration and Production

Aberdeen

w.derkinderen@expro.shell.co.uk

API/ASME Gas Lift Workshop, Houston, February 2001

Subsea gas lift

• why is gas lift optimisation of subsea wells so difficult?

• what are the consequences of limited testing and surveillance?

• how can we improve testing and surveillance in a cost-effective way?

injection rate (*1000m3/d)

typical GL performance curve (fixed FTHP)

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500

1000

1500

2000

0 50 100 150 200

net or gross (m3/d)

influence of wellhead choke or flowline

0

500

1000

1500

2000

0 50 100 150 200injection rate (*1000m3/d)

gross (m3/d)

Problems of subsea gas lift

• flowline/riser system is prone to severe slugging: – limited validity of steady-state models– difficult well kick off (risk of platform trip)

• subsea wells are hardly ever surveyed (expensive access)

• wells are sporadically tested (oil deferment)

• downhole gauges/flowmeters are lacking/ malfunctioning

• wells usually share flowline to platform:– FTHP cannot be considered constant – over-injecting lift gas causes oil deferment

Well testing

• long flowline -> several hours stabilisation time (typ. > 8 hrs after GL rate change)

• slugging -> long test times (typ. >6 hours)

• difficult to test at normal operating conditions– cumbersome playing with chokes to match normal

FTHP

• multi-rate testing of one well takes days

Limited survey and test data

• usually just one P/Q datapoint at one lift gas rate available

• lift point, reservoir pressure, and IPR are uncertain:– too many degrees of freedom to match well and

flowline models

• performance analysis is very time-consuming• models are useless for lift gas allocation and

well routing

How to improve surveillance in a cost-effective way?

• use pressure drop across subsea oil chokes for production trending:– install dP transmitters (FTHP and manifold pressure

gauges are too inaccurate at small dP)

• install distributed temperature sensors (DTS) in the wellbore

• apply modified ‘piggy-back’ well test method: – less production deferment– reduced slugging problems – multi-rate test data available

Gannet D field - central North Sea

6”6”

4” (gas lift)

MPM Bulk Sep

Bulk Sep

R31

R32

Gannet A

Gannet G

Test Sep

GD-01

GD-02

GD-03

GD-04

GD-06

Andrew Tay reservoirs

GD-06

subsea manifold

15.5 km from platform

New well

4 well test campaigns cost 2 MM£/yr

Testing two subsea wells simultaneously

• standard ‘piggy-back’ testing is not possible:– the FTHP of well A changes when well B is added to

the test flowline:– therefore, the production of well A is no longer

known unless its PQ curve is first established:– this requires a multi-rate well test, or a calibrated

well model

• combined test data can be unravelled:– by assuming that the PQ and lift performance

curves of a well can be linearised around an operating point

Linearised PQ curves

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0 100 200 300 400 500 600 700 800 900

Gross flowrate (m3/d)

TH

P (

bar

)

Well model, no GLLinearised, no GLmodel, GL 20 Km3/dLinearisedmodel, GL 40 Km3/dLinearised

Linearised GL curves

0

50

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0 10 20 30 40 50 60 70 80 90

Lift gas injection rate (Km3/d)

Gro

ss

flo

wra

te

(m3/

d)

model, THP 50 barmodel, 55 barmodel, 60 barLinearised, 50 barLinearised, 55 barLinearised, 60 bar

Linearised equations

cQbaTHPQ 1gl1well1well ,where the constant c includes the reference Qgl and THP

Around an operating point for well 1:

For a second well:

fQedTHPQ 2gl2well2well ,

Adding both wells:

2well1welltotal QQQ

6 unknowns (a, b, c, d, e, f) ----> 6 independent equations to be solved

The production of a well can be written as a function ofthe wellhead pressure (THP) and the lift gas rate (Qgl)

Dual well test

6total

5total

4total

3total

2total

1total

62gl62w61gl61w

52gl52w51gl51w

42gl42w41gl41w

32gl32w31gl31w

22gl22w21gl21w

12gl12w11gl11w

Q

Q

Q

Q

Q

Q1

1QTHP1QTHP

1QTHP1QTHP

1QTHP1QTHP

1QTHP1QTHP

1QTHP1QTHP

1QTHP1QTHP

f

e

d

c

b

a

,

,

,

,

,

,

,,,,

,,,,

,,,,

,,,,

,,,,

,,,,

Procedure:1. Select two wells for combined testing2. Test most prolific well at one THP and GL rate3. Add second well and select GL combinations4. Use choke to change THPs if required5. Solve inverse matrix to find a, b, c etc. (Excel macro)

Matrix of measured THPs and GL rates

Dual well test - input data set

Well 1 Well 2 Total

THP1 GLrate THP2 GLrate Q gross(bar) (Km3/d) (bar) (Km3/d) (m3/d)

Test 1 59 0 654.2Test 2 68.3 41.1 576.5Test 3 71.1 38.5 71 41.1 685.4Test 4 58.1 36.8 57.6 38.8 1014.5Test 5 53.1 44.7 52.2 0 1117Test 6 49.5 20.8 50.6 0 967.3GL reference rate 20 0

Example:

Input data plot

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Total gross flowrate (m3/d)

TH

P (

barg

)

test 1, GD4 only, no GL

test 2, GD4 only, 40 K GL

test 3, GD01 (40 K) + GD04 (40 K)

test 4, GD01 (40 K) + GD04 (40 K)

test 5, GD01 (45 K) + GD04 (no GL)

test 6, GD01 (20 K) + GD04 (no GL)

Split after matrix inversion

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0 200 400 600 800 1000 1200

Gross flowrate (m3/d)

TH

P (

barg

)

test 1 GD04, no GL

test 2 GD04, 40 K GL

split test 3

split test 4

split test 5

split test 6

GD04, no GL

GD04, 40 K GL

GD01, 20 K GL

GD01, 37.5 K GL

GD01, 45 K GL

GD04: 20.25 sm3/d/bar

GD01: 6.04 sm3/d/bar

How to unravel BSW and GOR?

Single well test of well 1 reveals BSW1 and GOR1

GOR2 = (Qgas,combined - GOR1* Qnet,1)/Qnet,2

Similar for the GOR of well 2:

Requires accurate well test measurements!

BSW2 = (Qwater,combined - BSW1* Qgross,1)/Qgross,2

Assumption: BSW and GOR are not rate-dependent:

• Deriving PQ curves from dual well tests is feasible

• Method works for gross, net and produced gas

• Method requires just one single well test (and 5 combined tests)

• Adequate accuracy for most purposes, but depends on input data quality (a.o. THP, liftgas rate)

• Provides valuable information for system model calibration (-> to generate actual P/Q and GL curves)

• Significant cost savings (1-2 MM£ for Gannet D)

• Now applied in other subsea fields of Shell Expro

Conclusions

• use multivariate analysis when more well tests are available

• use downhole gauge data where available

• use oil and/or water composition from samples to improve production allocation

• extend method to multiple well testing

Enhancements