taqa bratani limited well and scale management in a mature ... · • fish left in well after...

POWERING A THRIVING FUTURE

Well and Scale Management in a Mature Subsea Field

September 2020

Charles Adoga

Contents

2

Introduction and Background

Production History

Scale Management History

Rejuvenation of Scale Management

Programme of Activity on MSS1 Rig

P18s1 Intervention Summary


Conclusion

Next Steps

Pelican Background

3

• Location: East Shetland Basin, NNS

• Discovered: 1975

• Field Online: Jan 1996

– Water Injection Jul - 1997

• Type: Subsea oil development tied back to the Cormorant Alpha

Platform 8 Km away

– 2 x 8” production flowlines, 1 x 8” water injection flowline

– 1 x 6” gas lift flowline

– 5 current gas lifted producers (includes 1 cyclic)

– 22 wells (5 injectors and 17 producers)

– 4 injectors

• Reservoir: Middle Jurassic Brent Group at 10,500 - 12,300 ft

TVDSS, OWC not penetrated

• Cumulative production: 78 MMstb

• STOIIP: 590 MMstb

– STOIIP in low permeability rock

– High permeability channel intervals – premature watercut

• Oil Properties:– API 34.8– Bubble Point 2340 psi– GOR 567 scf/stb

4

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Oil

rate

(bopd)

Pelican Production History Nov 2008 - Mar 2019P20 Nov 2010 P18s1 Aug 2011 P21 Feb 2012 P22s1 Aug 2013

W23 injector drilled to

support P22 Sep 2015

P14s4 Aug 2018

P10Bs2 Sep 2010

Exte

nd

ed

Sh

utd

ow

n

Production History (TAQA operatorship)

45

6

Platform FlowlineDeployment

Rig / LWIV Subsea Acid SkidManifold

2001 - 2002 2005 - 2008 2009 - 2011


5

Deployment option depends on:

• Economics

• Cheapest – Platform flowline

• Most expensive – Rig / LWIV

• Risk of diversion

• Platform flowline – risk of debris impairment

• Other planned well activities

Never

used h

isto

rically

Deployment Technique


Pre 2011

• Active infill well drilling & interventions

• Scale prevention via inhibition & treatment (dissolver + squeeze)

• Good water injection uptime

2011-2017

• P10bs2 scale inhibition squeeze in 2011

• Poor water injection uptime

• P22s1 coreflood test – 50% return permeability impairment

2017-date

• Rejuvenation of scale management & change of production storage to direct export

• Laboratory Tests (P22s1 repeat, P12 expanded coreflood tests)

• Scale remediation via scale dissolver treatment

6

Timelines


Reservoir Performance

• Downhole pressures

• CITHPs

Well performance

• Well test

• Gas lift design reports

Production Impairment mechanism

• Production chemistry data

• Lab tests

• Barite / Carbonate Envelope

7

• Pressure

• Productivity index

• Artificial Lift challenges

• Fines migration

• Scaling

• Fluid / Rock interaction

• Flowline impairment

Approach

UncertaintySystem integration Available Information


8

Integration of well performance and scale model output

predicted severe scaling, although by standard

analysis, moderate scaling severity was suggested

Impact of Historical Scale Management Data Interpretation & Integration

P18s1

15

515

1015

1515

2015

2515

3015

3515

4015

4515

50 70 90 110 130 150 170 190 210 230 250

Flo

win

g P

ressure

s(p

sia

)

Flowing Temp (deg F)GLM location

Calcite Envelope with PT transverse.

• Over 90% of initial productivity of well impaired

• Sub-optimal gas lift performance

• Poor well performance contributed 20-30%

reduction in recoverable reserves

Programme of Work on MSS1 Rig

9

#1 P18

Data acquisition (PLT & RST)

Reperforation

Dissolver Treatment (Contingency)

Gas lift valves C/O

GLV Acid pickle (Contingency)

#4a P22


Potential WSO

#2 P13

Dissolver treatment

Gas lift deepening

GLV Acid pickle (Contingency)

#3 P14

Dissolver treatment


Potential WSO

#4b P22

Dissolver treatment

Initial Scopes

P18 Intervention Summary

10

Scale deposition

• Drift hung up at 9,240 ft. Target depth of 12,626ft

• Calliper log revealed the extent scaling

• 3rd and 4th GLM covered completely with scale

• Pervasive scale present across perforation

• CT mobilised and carried out:

• 6 milling runs (~3,300ft scale milled)

• 3 Cal-Acid dissolver treatments (306 bbls) and

• target depth below the perfs reached

Well Access, Caliper Log, Milling & Dissolver Treatments

3.8”

2.8”

Reservoir

Section

Before

After


11

33% 29% 25%0.20

0.72

1.26

2019 Pre-Intervention 2019 Dissolver Treatment 2019 Reperforation

Watercut Productivity index

• Dissolver Treatment effective in improving well productivity

• Dissolver Treatment enhanced Vertical Lift Performance

• reinstated gas lift orifice valve operability confirmed with FGS

• Selective reperforation from saturation log prevented adding perf in

watered zones

• Planned 3-3/8” gun changed to 2-7/8” to prevent gun getting stuck

post perforation

• GLV change out was cancelled due to perceived challenges to carry out

change out

Re-perforation & Result


12

Well Initial Scope Executed Scope

P14 • Dissolver treatment

• Data acquisition (PLT &

RST)

• Potential WSO

• Wireline runs & dissolver

treatments to gain access to

perfs

• Slickline fishing

• Dissolver treatment

• Data acquisition

• P14s4 came online in August 2018 with initial watercut reaching 70%.

• Scale encountered ~600ft above top perforation

• Reservoir access established via dissolver treatments c/w wire brush.

• Fish left in well after establishing reservoir access, but access for data acquisition not affected by fish.

• Data acquisition completed

• Saturation logs revealed swept intervals

• Production logs showed oil production being suppressed by jets of water

• Flowing Gradient Surveys across GLMs confirmed optimal performance


13

#1 P18


Reperforation

Dissolver Treatment (Contingency)

#2 P13

Dissolver treatment

#3 P14

Dissolver treatment


Completed scopes

14

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Ju

l-1

8

Se

p-1

8

Oc

t-1

8

Dec

-18

Fe

b-1

9

Ma

r-19

Ma

y-1

9

Ju

l-1

9

Au

g-1

9

Oc

t-1

9

BO

PD

Daily Allocated Production

Pelican Pre-

Intervention

Post Intervention

production

Intervention

Incremental

1870 bopd


Production Incremental

Conclusions

15

Integration & Communication

• Intervention team comprised production engineer, intervention and completion engineers and management

• Daily meetings with management for:

• Intervention progress

• Daily campaign economic return updates

• Scopes balancing

Scale

• Scale modelling was helpful in predicting wells with scaling presence

• Dissolver treatments helped in removal of scale but need mechanical agitation / mill to remove significant quantities

Data Acquisition

• Acquired saturation log was critical in optimising the reperforation to avoid swept zones

• Acquired production log was useful in identifying zone for future water shut-off

Operational contingencies/learnings

• Coil tubing contingency – acidizing and tractor milling alone may not sufficient to remove extensive scale from wells

• Flexibility in perforating guns configuration should be considered

Scale Management

Next Steps

• Continue Well performance monitoring

• Welltests and

• Production chemistry data acquisition

• Data analyses and integration

• Approval to carry out dissolver treatments in

2021

• Subsea intervention in 2020 to confirm

functionality and operability of the subsea

scale squeeze skids - completed

• Execute approved dissolver treatment scopes

in 3 wells in 2021

• Plan P&A activities with robust contingencies

for scale in tubing

16

ROV footage of Pelican Subsea stim skid

Acknowledgement

Many thanks to TAQA for giving the permission and support to present this material.

Also thanks to Jane Tomkinson and the Cormorant Alpha Subsurface & Wells Teams for their great support during the planning and execution of the 2019 Pelican Intervention on the MSS1 Rig.

Finally, thanks to the Devex organising committee for the opportunity to present today.

17

THANK YOU

P13 Intervention Summary

19

• Well had not been entered since its completion in 1996 apart from a

scale dissolver treatment pumped from the Corm Alpha in 2009.

• Initial drift hung up 15ft below tubing hanger. Wax deposit found.

• Tubing eventually cleaned to TRSSSV with combination of wire brush

and Base Oil soaks (200bbls).

• Shock sheared FIT whilst trouble shooting TRSSSV issue. Found fish at

6300ft and recovered.

• Ran 3” deep drift and held up at 6,900ft. Suspected scale.

• Pumped dissolver treatments (683bbls) and GLVs changeout cancelled

Well Initial Scope Executed Scope

P13 • Dissolver treatments

• Gas lift deepening

• GLV Acid pickle

(Contingency)

• Wax removal

• Re instatement of TRSSSV

• Fish recovery

• Dissolvers treatments

2nd HUD – scale suspected

1st HUD – Wax deposit


Milling & Dissolver Treatment

20

20

3.8”

nominal

Before After

Reservoir Section

taqa bratani limited well and scale management in a mature ... · • fish left in well after...

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