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A Case Study in Evaluating Technical Options for Well Abandonment in an Aging Offshore Field

Tom Leeson: Reverse Engineering

Stewart Buchan: Quadrant Energy

Aberdeen: June 2017

http://www.resleng.com/

Commercial-in-Confidence ©1992 to 2017 RESL - All Rights Reserved2 -

HARRIET JOINT VENTURE (HJV)

• 45 Wells across 9

Unmanned

Structures

• 4 Suspended

Subsea Wells

• 4 Land Wells


• Develop AACE Class IV Time and Cost Estimates for Abandonment– Review offset well abandonment results

– Evaluate local regulatory constraints on abandonment design

– Develop individual well methodologies for a ‘Conservative’ case & an ‘Opportunity’ case

– Develop Technical Risk Register

– Develop individual well durations

– Develop cost database

– Undertake Monte Carlo probability analysis of overall Project Cost for both Cases

• Evaluate Opportunities for Cost Minimisation especially the potential for using Rigless Techniques

SCOPE OF WORK


Well Characteristics– Mudline Hangers and Annuli Cemented at surface/mudline

– Sustained B and C Annulus Pressures: Sources Uncertain

– Total Losses to ~ 650m and unknown cement top in B Annulus

– Shallow Gas Bearing Zone(s) with limited flow potential: ~1,000m-800m (Windalia/Gearle)

– Tubing & Wellhead Integrity

– Limited High s.g. Tail Cement Volumes

– Effectiveness of existing Suspension Plugs

– Multiple Production Reservoirs (5 Wells)

Goal-Oriented Regulation

Limited Platform Load Capacity & Water Depth (30m-6.5m)

CHALLENGES & OPPORTUNITIES


• Isolation ‘Barrier’ required across the wellbore

• Single ‘Combination’ barrier permitted

• Hydrocarbon Cross-flow not permitted (deeper formation in 5 wells)

• Tubing and GLM leaks assumed to prevent thru’ tubing operations

• Sustained B and C annulus pressures assumed to originate from reservoir formation

• Remedial cementation of cemented annuli via section milling

• Remedial cementation of casing with uncertain cement and liners, by perf and wash technology

• Plugs below tailpipe only when hole angle <75deg

• Cementing of 7” liner in 12 ¼” hole: unreliable at high hole angle

• Windalia and Gearle require isolation from surface at 13 3/8” shoe due to loss formations above this point

ABANDONMENT PHILOSOPHY –CONSERVATIVE CASE


ABANDONMENT METHODS – EXAMPLE 1

Conservative Case Kill Well and Plug Tailpipe

N/D XT & N/U BOP

Pull Tubing & Set BP in Liner Hanger

Section Mill Casing & Set Cement Plug #1

Set Squeeze Packer at 13 3/8” Shoe

Circulate or Squeeze Annulus

Sting Out and Set Cement Plug #2 on Top

Cut & Pull Inner Casings

Set Bridge Plug

Set Plug #3

Well Name: Artreus-1

Conservative Case P&A Schematic

ML to KB: 49.8 m

Water Depth: 8.1 m

Drilling Rig: Ensco 56

Spud Date: September, 2005

Rig Release: September, 2005

20" Conductor @ 49.5 m

No Cement Details.

13 3/8" Casing Shoe @ 801.6 m

No Cement Details.

Tail TTOC @ 705m

Primary Data Source for this work: Well Summary and Integrity Review

9 5/8" Casing Window Top @ 1,400m

9 5/8" Casing Window Bottom @ 1,404 m

No Cement Details.

8 ½” hole @ 4,046 m

Lead TOC @ 3,585 m

Lead TTOC @ 650 m

Lead TTOC @ 250 m

7" Liner Shoe @ 4,043 m

No Cement Details.

9 5/8" x 7" Liner Hanger/Packer Top @ 1,365 m

EOT 4½” @ 1,574 m

7" x 4 ½” AHC Packer @ 1,554 m

Perfs: 3,680 – 3,868 m

RAW 28th December, 2016

Abandoned

Agincourt-6H

Cement Note

· No cement details in report.

· TTOC from Completion Schematic.

Set Plug in Nipple

Section Mill Casing

Cut and Pull Tubing below Bridge Plug

Cement Plug #1

Cement Plug #2: Perf and squeeze

cement at 13 3/8" Shoe.

Squeeze Packer

Cement Plug #3

Bridge PlugCut and Pull Casings below Bridge Plug

Bridge Plug

Well Status: Inactive

Wellhead Test Failures

· No recorded issues.

Annulus Pressure

· Sustained B Annulus Pressure


Changes from Conservative Case• Sustained annular pressures assumed to be from Windalia/Gearle

– Still need Annular Reservoir Barrier in 7 wells

• Quality of unknown casing cementation can be verified successfully by logging

• Small tubing leaks do not prevent through tubing cementation operations

• Cross flow between hydrocarbon reservoirs permitted

• No surface plug required

ABANDONMENT PHILOSOPHY –OPPORTUNITY CASE


ABANDONMENT METHODS – EXAMPLE 2

Opportunity Case Kill Well and Plug Tailpipe

N/D XT & N/U BOP

Pull Tubing

Verify Casing Cement

Set Plug#1 on Bridge Plug & Verify

Set Squeeze Packer at 13 3/8” Shoe

Circulate or Squeeze Annulus

Sting Out and Set Cement Plug #2 on Top

Well Name: Artreus-1

Opportunity Case P&A Schematic

ML to KB: 49.8 m

Water Depth: 8.1 m

Drilling Rig: Ensco 56

Spud Date: September, 2005

Rig Release: September, 2005

20" Conductor @ 49.5 m

No Cement Details.

13 3/8" Casing Shoe @ 801.6 m

No Cement Details.

Tail TTOC @ 705m

Primary Data Source for this work: Well Summary and Integrity Review

9 5/8" Casing Window Top @ 1,400m

9 5/8" Casing Window Bottom @ 1,404 m

No Cement Details.

Well Status: Inactive

8 ½” hole @ 4,046 m

Wellhead Test Failures

· No recorded issues.

Lead TOC @ 3,585 m

Lead TTOC @ 650 m

Lead TTOC @ 250 m

7" Liner Shoe @ 4,043 m

No Cement Details.

9 5/8" x 7" Liner Hanger/Packer Top @ 1,365 m

EOT 4½” @ 1,574 m

7" x 4 ½” AHC Packer @ 1,554 m

Perfs: 3,680 – 3,868 m

RAW 28th December, 2016

Abandoned

Agincourt-6H

Cement Note

· No cement details in report.

· TTOC from Completion Schematic.

Set Plug in Nipple

Cement Plug #1

Cement Plug #2: Perf and squeeze

cement at 13 3/8" Shoe.

Squeeze Packer

Cut and Casings and Conductor at ML

Bridge Plug above hanger

Cut and Pull Tubing below Bridge Plug

Annulus Pressure

· Sustained B Annulus Pressure


DURATION ESTIMATES

28.6 58.6

10.0% 10.0%80.0%

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

10

20

30

40

50

60

70

80

LB Pull Completion - Normalised to 2000m lengthTriang(17.875,39,72)

Low MostLikely High

PositionRig

LBMoveinonDPandJackUp 5.0 6.0 8.0

LBSkidCantileverandprepareforoperations 7.0 9.0 12.0

LBInstallwalkway 10.1 12.6 15.1

P&APreparations

LBTubingandAnnulusRiserandPCEpreparations 21.2 21.8 22.4

PrepareWell

LBRigupW/SPCE&riserlinestotree&annulus 2.5 5.8 11.0

LBBullheadkillfluidtoformation 4.0 6.0 10.0

LBR/UwirelinedriftwellandlockopenSSSV 6.0 8.0 15.0

ThroughTubingReservoirPlug 0.0 0.0 0.0

LBDrifttoPacker&setplugintailpipe 8.0 10.0 18.0

LBPunch/severtubingandcirculateannulusclean 6.0 8.0 18.0

LBcirculate800'balancedcementplugviatubingandverify 8.0 10.0 15.0

LBRIHCBLandLogAnnularcement 4.8 6.0 9.0

LBRIHandsetsqueezepackeraboveperforations 18.0 22.5 33.8

LBMixandsqueezecementintoperfs 3.0 4.0 8.0

LBstingoutofpackerandspotcementplugonpackerandverify 6.4 8.0 12.0

PullCompletion

LBsever/punchtubingatshallowdepth(Typically@133/8"shoe) 2.0 4.0 6.0

LBsettemporarypluginTubinghanger 2.0 3.0 5.0

LBRemoveTree 4.9 10.0 20.6

LBNippleupBOP's 4.8 8.4 15.0

LBRIHandlatchtubinghangerandrecoveruppertubingsection 6.0 7.5 11.3

LBRIHandlatchtubinghangerandlifttubingstring 4.0 5.0 7.5

LBmixandspot800'cementplugthrutubingandverify 8.0 10.0 15.0

LBPullCompletion-Normalisedto2000mlength 17.9 39.0 72.0

LBRIH,latchandretrievepacker 24.0 30.0 48.0

PrepareCasedHole

LBcutandpull95/8"casing 12.0 15.0 22.5

LBCut&Pull133/8"casing

LBRIHCBLandLogAnnularcement 4.8 6.0 9.0

IsolateCasedHole

LBRIHBridgePlug,set,stingout,spotcementontopandverify 14.4 18.0 27.0

LBRIHandsetBridgePlug/SqueezePacker 6.0 7.5 11.3

LBPerforateCasingandCirculateannulusclean 6.4 8.0 12.0

LBMixandsqueeze/circulateannuluscementplug 4.8 6.0 9.0

LBWOCandverify 6.4 8.0 12.0

LBRIH,spotcementplugandverify

IntermediateIsolation

LBcutandpull95/8"casing 12.0 15.0 22.5

LBRIHSqueezepackerandset 6.0 7.5 11.3

LBPerforateCasingandCirculateannulusclean 6.4 8.0 12.0

LBMixandsqueeze/circulateannuluscementplug 3.2 4.0 6.0

LBStingout,spotcementandverify 6.4 8.0 12.0

LBcirculatebalancedcementplugviatubingandverify 8.0 10.0 15.0

LBCut&Pull95/8"casing

LBCut&Pull133/8"casing 12.0 15.0 22.5

LBRIHBridgePlug,set,stingout,spotcementontopandverify 14.4 18.0 27.0

SurfaceIsolationandConductor

LBCut95/8"casingandN/DBOP 5.4 10.4 13.5

LBSkidbackCantilever 4.0 6.0 8.0

LBCutCasing&Conductor 4.0 5.0 8.0

LBRecoverconductor(HA/Linda&Wonnichonly) 6.0 8.0 18.0

LBConfirmConductorSeverancewithVesselCrane 0.5 1.0 2.0

MOB-DEMOB

LBJackDownandmoveofflocation 4.0 5.0 8.0

LiftboatbasedDurations

Duration(Days)


SCHEDULE OPTIONS - EXAMPLE

Option 1:

Mob Liftboat first,

finish wells with the

Rig

Option 2:

Mob Rig first, finish

remaining wells (and

remove facilities?)

with the Liftboat


PRINCIPAL RESIDUAL TECHNICAL RISKS

• Source of Sustained Annulus Pressures– Potential impact: Reservoir isolation via section

milling

• Unknown Quality and Extent of Annular Cement

– Failed Cement Barriers, delays Pulling Casing

• Section Milling in High Angle Hole– Delays

• Surface Isolation Valve Functionality– Circulation Failures

• Casing Leaks– Failed Barriers, Compromised Circulation Paths

• Pressure and/or Undetonated Guns below Shallow Cement Plugs

– Alternative Intermediate Abandonment

SeverityThreat Event Preventative Barriers Mitigating Controls Likelihood Safety Environment Asset Reputation Further Actions

Rig up on well

2 Annulus valves seized

or not in place

inability to access

analulus and/or

circulate

Wellhead maintenance

programme prior to rig

arrival

6. PROBABLE:

Consequence or event

has occurred within the

Company (Between 1

and 10 incidents every 10

years)

1. NEGLIGIBLE: First Aid

injury

1. NEGLIGIBLE:

Environmental damage

lasting less than 1 week

3. MODERATE: Material

or production

loss/deferment between

$10M-$50M

1. NEGLIGIBLE: Short

term local impact

(community)

3 Pressure on A annulus leak from

hydrocarbon

formation via failed

packer, tubing and/or

casing

Bleed down pressure prior

to arrival and establish if

related to tubing/packer

leak or B Annulus

7. EXPECTED: With the

existing controls in place,

is expected to occur in

most circumstances at

the location during the

lifecycle phases or

phases being assessed.


injury

1. NEGLIGIBLE:




or production


$10M-$50M


term local impact

(community)

If required, design more

complex well kill

4 Pressure on B and/or

C Annuli

leak from

hydrocarbon

formation via failed

cement and/or casing

Bleed down pressure prior

to arrival and establish if

source is from reservoir or

shallow formations






lifecycle phases or



injury

1. NEGLIGIBLE:




or production


$10M-$50M

3. MODERATE: Short

term national coverage,

JV oversight impact

If required, remove well

from rigless programme

and require remedial

cementation of production

casing with rig.

Mill shallow cement plug

6 Pressure below

cement plug

Loss of Containment well control and kill

weight brine in place

5. LIKELY: Has

occasionally

occurredwithin the

industry & the team has

had first hand experience

(Between 1 and 10

incidents every 100

years)

3. MODERATE: Lost

Time Injury (LTI)

2. MINOR:


lasting from 1 week to 1

month

3. MODERATE:

Material or

production

loss/deferment

between $10M-$50M

3. MODERATE: Short

term national

coverage, JV oversight

impact

Brief crews and develop

contingency plans

7 undetonated guns

below squeeze packer

to be milled

fishing of guns contingency plans and

tooling

5. LIKELY: Has

occasionally

occurredwithin the

industry & the team has

had first hand experience

(Between 1 and 10

incidents every 100

years)

1. NEGLIGIBLE: First

Aid injury

1. NEGLIGIBLE:



3. MODERATE:

Material or

production

loss/deferment

between $10M-$50M


term local impact

(community)

investigate alternate of

cementing in guns at lower

depth downhole

Section Milling

25 Milling in high angle

hole (~>45deg)

Snapped knives, Loss

of BHA

Careful control of milling

parameters, establish

cement behind casing with

log prior to milling window






lifecycle phases or



injury

1. NEGLIGIBLE:




or production


$10M-$50M


term local impact

(community)

Lost tubular will need to be

fished causing additional

duration - factor into cost

estimate as a risk

Setting Cement plug in casing/annulus

29 Anulus cement lower

than anticipated

change to

abandonment

method

programme

contingency required

including alternative

tooling

6. PROBABLE:

Consequence or event

has occurred within the

Company (Between 1

and 10 incidents every 10

years)


injury

1. NEGLIGIBLE:




or production


$10M-$50M


term local impact

(community)

develop programme

contingency for additional

annulus cementation by

perf and wash or annulus

circulation

30 Annulus cement

higher than expected

change to

abandonment

method

programme



tooling






lifecycle phases or



injury

1. NEGLIGIBLE:




or production


$10M-$50M


term local impact

(community)

develop programme

contingencies for

cementation higher in

wellbore, perf and

squeeze/wash, and/or

section milling

31 Casing leak(s) effective circulation

prevented

programme



tooling






lifecycle phases or



injury

1. NEGLIGIBLE:




or production


$10M-$50M


term local impact

(community)

develop programme

contingencies for loss

control, cement squeeze

and/or alternative

abandonment

Hazard Identification Engineer to Populate


• Regulator Agreement

• Unit Cost Inflation (Rates are Low, but for how long?)

• Alternative (Local) Liftboat

• New & Emerging Technologies/Methods– Logging thru’ tubing

– Reduced cement plug length

– Alternatives to conventional section milling

– Alternative barrier materials

– Removing the need to pull tubing

• Synergies with Facilities Decommissioning

• Suspended Well Risk Assessment

ADDITIONAL STRATEGIC RISKS & OPPORTUNITIES


• Single Mobilisation of Each Asset *

• Liftboat and Rig mobilised to/from Singapore*– * Exception: US$ 25k/day amortization for rig opportunity case (based on previous QE

experience)

• Significant Inclusions– Safety Case

– Liftboat Cantilever Mods

– Supply Base and Dedicated Supply Boats & Helicopters

– WOW and Cyclone Provision

• Offset Operations Durations & Recent Unit Costs used where Possible

COST ANALYSIS


RESULTS

Conservative Case P50: 389 rig days plus 184 liftboat days

Opportunity Case P50: 137 rig days plus 284 liftboat days –

27% cost reduction

197.59 211.58

10.0% 10.0%80.0%

0

1

2

3

4

5

6

7

8

185

190

195

200

205

210

215

220

225

Valu

es

x 1

0^

-8

Values in Millions ($)

Opportunity Case Total


MOST LIKELY CASE

Quantification of Risk Impact Required

• Example: Additional Surface Plug (~USD17.4M

Impact)

Opportunity

Case

Conservative

Case

Likely Cost

Most Likely Case

$$$$$$$


• Early & Sustained Dialogue with Regulator

• Follow up Risk Register Actions to Reduce Unknowns

• Finalise Most Likely Case

• Liftboat cost savings are limited until rig rate escalates or local liftboat option is feasible

• Investigate Local Liftboat Options & Contractor Model

• Confirm Facilities Strategy before Committing to P&A Strategy

• Significant further cost reduction opportunities through– Understanding source of annular pressures

– Understanding condition of tubulars

– Alternatives to section milling

– Challenging multizone isolation, surface plugs etc.

• Declaring suspended wells as abandoned requires further study

RECOMMENDED ACTIONS & CONCLUSIONS

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