Reducing Well Test Deferments from Clusters of

Gas-Lifted Sub-Sea Wells

Philip Holweg

Wim der Kinderen

(Shell Expro)

API Gaslift WorkshopWoodbank, Aberdeen

12 November 2001

Reducing Well Test Deferments fromClusters of Gas-Lifted Sub-Sea Wells

Outline:

• Why sub-sea clusters are difficult to test• Well testing by difference - methodology• Example from Gannet• Benefits of testing by difference• Conclusions

Issues in Well Testing Subsea Clusters #1

Significant deferment when well testing subsea

• flow line usually is a production constraint– test line often used to maximise production

• multi-rate tests result in sub-optimal production– choke wells to change THP– change gaslift to assess gaslift performance– deferring production for duration of the test

• long stabilisation times for long tie-backs– fluids must travel from near well bore to facilities to

accurately measure BSW, GOR– stabilisation time even longer for gaslifted wells

• also need to stabilise annulus pressure

Issues in Well Testing Subsea Clusters #2

Often no dedicated test line available

• single well on large flow line causes more deferment – even longer stabilisation period due to low

velocities

• single well on large flow line can induce slugging– need to choke well back to stabilise - further

deferment– long averaging period required

• risk of wax and hydrate deposition– reduced flow rates cause lower pressures and

temperatures

Approach:

• Test wells together– usually in normal configuration

• Induce controlled changes– change THP through choke or gaslift change

• Measure production change by difference

• Feed data into linear PQ curve model– calculate individual well performance (PQ curves) for

all wells

Testing Wells Together - by Difference

Linearised PQ Curves

0

10

20

30

40

50

60

70

80

90

100

0 100 200 300 400 500 600 700 800 900Gross Flow Rate (m3/d)

TH

P (

bar)

20

40

0

Gaslift(103 m3/d)

Well Model

Linearised

CQBQATHP glwellwell 1,11

cQbaTHPQ 1gl1well1well ,

rewrite:

A

Cc

A

Bb

A

1a

where:

the constant C includes reference lift gas rate

Linearised PQ curves

cQbaTHPQ 1gl1well1well ,fQedTHPQ 2gl2well2well ,

2well1welltotal QQQ

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

,

,

,

,

,

,

,,,,

,,,,

,,,,

,,,,

,,,,

,,,,

Calculation for Dual Well Test

Generalised Methodology

• More test points than unknowns improves accuracy• Measurement uncertainty can be included• THP data points can be replaced by PDG

measurements– improves accuracy

• Require one single well test to avoid singular data set– unless PDG is available (measure SIBHP using PDG)

• Methodology works also with more than 2 wells

QpA

QAAAp TT 1

/AS

Examples from Gannet

• 7 fields tied back to facilities at single platform– 6 subsea fields

• Long tie backs– 3 to 15 km– most fields are gaslifted– limited test lines

FieldDistance

(km)GasliftTest Line

D 15 E 14 F 12 G 5

GD-01

GD-02

GD-03

GD-04

GD-06

Andrew Tay

6”6”4” (blocked)

4” (gas lift)

MPM Bulk Sep

Bulk Sep

R31

R32

Gannet A

Gannet G

Gannet D

Test Sep

15.5 km to Gannet A

Gannet D - Schematic Overview

THP(bar)

67.8

Test 4

Test 5

Test 6

Gaslift (103 m3/d)

Gannet D - Dual Well Test Programme

THP(bar)

Gaslift (103 m3/d)

Q gross (t/d)

Well 1 Well 2 Total

Test 3

Test 2

Test 1

71.1

58.1

53.1

49.5

38.5

36.8

44.7

20.8

69.6

57.6

52.2

50.6

41.1

38.8

0

0 862.5

1001.4

905.3

583.6

41.2 518.30 0

0 0 56.6 0 602.6

Gannet D - Derived PQ Curves

Gross Flow Rate (t/d)

0

10

20

30

40

50

60

70

80

0 200 400 600 800 1000 1200

TH

P (

bar)

Single Test 1Single Test 2Combined Test 3Combined Test 4Combined Test 5Combined Test 6

Gannet D - Derived PQ Curves

Gross Flow Rate (t/d)

0

10

20

30

40

50

60

70

80

0 200 400 600 800 1000 1200

TH

P (

bar)

Single Test 1Single Test 2Combined Test 3Combined Test 4Combined Test 5Combined Test 6

040 .103 m3/dGaslift: 20 38 45

GD-01 GD-04

Gannet D - Derived PQ Curves

Gross Flow Rate (t/d)

0

10

20

30

40

50

60

70

80

0 200 400 600 800 1000 1200

TH

P (

bar)

Single Test 1Single Test 2Combined Test 3Combined Test 4Combined Test 5Combined Test 6

040 .103 m3/dGaslift: 20 38 45

GD-01 GD-04

Benefits - Example for 2 Well Cluster

0200400600800

1000

Rate

(m

3/d

)

1 2 3 4 5 6

normal operationstabilisationmeasurement

Conventional

0 24 48 72 96 120 144 168Time (hours)

0200400600800

1000

Rate

(m

3/d

)

By Difference

Assumptions:• Individual rate: 500 m3/d• Combined rate: 800 m3/d

ConventionalBy difference

Benefit

Time(hours)

Deferment(m3)

10576

1540320

25% 80%

Testing by Difference - Provisos

• Need capability to measure cluster production– difficult when multiple fields are commingled

• Wells must be stable over test period– gas coning wells may be less suitable

• Still need one test point with single well flowing– unless a PDG is available

• Assumption of linearised PQ curves not always valid– especially for gaslifted wells at higher THPs

• apply multiple slopes for one well• gather more test points

Conclusions - Testing by Difference

• Significant reduction in well test deferment– especially for gaslifted subsea wells– typically saves 80% hydrocarbon deferment & 20 %

test time– avoids adverse flowline conditions

• slugging• low p, T

– PDGs allow further deferment reduction• no single well test point required

• Quality of well tests not affected– approximation of linearised PQ curves usually

proves not to be a limitation• extend linear model per well if necessary

– PDGs make this method more accurate & simpler