GAS LIFT OPERATIONS IN APACHE’S NORTH SEA REGION

ROSS LITTLEWOOD

PETER SORDYL

36th Gas-Lift Workshop, Stavanger, Norway, February 4 – 8, 2013

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Introduction

Apache North Sea

Gas Lift vs. ESP

Typical gas lift completion and equipment

Gas lift surveillance, optimisation and troubleshooting

Common misconceptions

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Apache in the North Sea Region

Beryl

Forties Forties Field - 97.14%

Beryl Field – ~57%

Bacchus – 50%

Maule – 100%

Net production: ~ 80Mboed

Gross production: ~150Mboed

Aberdeen

Stavanger

Bacchus

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The Forties Field

ESP wells

10 ESPs

ESP wells

15 ESPs

16 ESPs

ESP & GL wells

1 GL

15 GL

4 ESPs

ESP & GL wells

2 subsea

4 ESPs

ESP & GL wells

17 GL

BERYL AREA SUBSEA FACILITIES

Linnhe

(disused)

BWISS

55

N4Y31Z

60

March 2007, UK_MIS-BE-3D-PR-0001

SPM2 SPM3

Beryl A

Beryl B

Buckland

Skene

4” Gas

to/from Leadon

(disused)

Ness South

Nevis South

Ness

N2

N8

N5Y

48

BK3 BK1BK2

BK4

N9

N3Z

S59

N1Y

N10

45Z38Z 61 51

20B42Z

N11

Ness Extension

N7Z

Nevis Central

S64

Nevis West Beryl

S66

Nevis North

BK5

LewisS62

33

Nevis South

S65 Cormorant

Oil Flowline

Water Injection

Bundle/PIP

Gas Lift/Export

Chemical Injection

Nevis

Far North

3x8” Flexibleflowlines

16” Gas

20” Oil8” Oil

16” Oil Export

to Gryphon

30” Gas

to St. Fergus

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The Beryl Field & Subsea Infrastructure

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49

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Gas Lift vs. ESP – Ever Changing Challenge!

Workovers

Gas Lift Issues 1. Numerous plant trips due to old equipment

& slow recovery times following shutdowns. 2. As more wells were drilled the lift gas

available per well was reduced.

Run More ESP’s 1. Poor ESP run lives (sand, shutdowns, etc.) 2. Rig crews spending time working over failed

ESP’s & unable to drill new targets. 3. Improved topsides efficiency reduced gas lift

“shoulder losses”.

More ESP’s or More Gas Lift? 1. Topsides projects have resulted in higher

available gas lift rates & more system redundancy.

2. Improved topsides efficiency – benefits both systems.

3. Improved ESP run life (sand control, ESP spec., etc.)

4. Expected well PI. 5. Availability of drilling facilities (i.e. FASP).

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Typical gas lift completion and equipment

P-DHSV

Tubing

Shallow Packer

Deep Packer

Sand Screen

Liner

Casing

Unloading valve

Two packers Shallow dual packer

Deep set production packer

G-DHSV & P-DHSV

Typical number of unloading vales: 2-4 valves

Typical size of the orifice valve: 3/16”, ¼”, 5/16”

Typical gas injection rate: 1.4 – 2.6MMscfd

Typical gas injection depth: ~ 1800m TVD

Typical size of the production tubing: 3 ½”, 4 ½”

Gas injection string 2-3/8”

Cased and perforated or sand control Cased & perf

Frac Pac

SSS

GP

Downhole gauge

Orifice Valve

Downhole Gauge

G-DHSV

Unloading valve

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Gas Lift troubleshooting on the basis example FD 3-2

Sidetrack in Oct 2008

10-3/4” shallow dual packer

3-1/2” tubing

2 unloading valves, orifice valve (¼”)

Distribution Temperature Sensing (DTS)

Deep 9-5/8” retrievable packer. Pressure set, overpull shear release.

Frac Pac

Scale squeeze due to BaSO4 formation risk

First scale squeeze (since sidetrack and recompletion)

Well came back on line with difficulty

difficult to kick off

different values for injection parameters (once well flowing) observed

Deep Packer

Dual Packer

Sand screen

P -DHSV

1st unloading valve

2nd unloading valve

Orifice valve

Down hole gauge

G -DHSV

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Gas Lift troubleshooting on the basis example FD 3-2

DTS clearly showed

No tubing leaks

Unloading valves were not passing

Packer calculations – during squeeze

Tubing contraction due to change (reduction) in temperature

Show forces greater exerted on the packer during the squeeze were greater than the shear pin specification

Suspected unseated packer

Intervention

Changed out orifice valve

¼” to 3/16” new orifice

General conclusions:

Improve completion (packer) specification

Improve pre-squeeze analysis

Packer calculations post the incident

Hot water squeeze for other wells with this specification packer

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Gas Lift valves replacement dictated by the gas availability

Gas lift system upgrade

Change-out of old 1st stage compressors

New compressors operating in parallel

GAP analysis for gas lift distribution

Prosper model analysis

Gas lift valves replacement program

Kickover tool – wireline operations

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PI Processbook as a useful tool for wells monitoring

Production choke position

Gas injection pressure

Well Head Flowing Temperature

Gas injection rate

Well head flowing pressure

Gas injection flow control valve

Bottom hole pressure

Well unstable unloading valve open

Well stable – gas injected only through the orifice

Wells monitoring Stability issues analysis and plan a way forward

Contact platform Wells start-up /

optimisation Well test and data

recording

Well shutdown for 5hrs

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Gas Lift Misconceptions

To address we now do the following:

PE’s must attend a gas lift course. Where possible follow up with a nodal analysis course

Good surveillance

Coaching and mentoring of younger PE’s in surveillance, optimisation techniques and troubleshooting – develop a good foundation and don’t let the misconceptions take hold!

Coaching sessions with offshore staff

Providing good start-up procedures

Short presentations offshore to familiarise the crew with gas lift operations. Include DHSV animation

Keep accurate and up-to-date records of gas lift designs

“We are going to let the well build up a head of steam” “There must be a sticky valve” “The annulus pressure is high. We must have a hydrate across the orifice”

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Thank you

36th Gas-Lift Workshop, Stavanger, Norway

February 4 – 8, 2013