taqa pelican devex 2011 · 2012-04-14 · taqa bratani devex 2011 – aberdeen - thursday 12 may...

TAQA Bratani

DEVEX 2011 – Aberdeen - Thursday 12 May – 16:35

Laurent SCHIRRER (presenter)

Rob KUYPER – TAQA Development Manager

Derrick HENDRY – Pelican subsurface team lead

Pelican subsea re-development 2010

- what went right ?

TAQA – Pelican 2010 campaign - DEVEX 2011 2

Forewords: did it go that right ?

Issues and challenges faced will also be presented

1- We’ll set the scene: what was done

2- Field description

3- Snapshots: an integrated, fast-track project from concepts and ideas to production

TAQ A Br a t a n i

D EVEX 2011 – Abe r d e e n - Th u r s d a y 12 M a y – 16:35

La u r e n t SCH IRRER (pr e s e n t e r )

Ro b KUYPER – TAQ A D ev e l o pme n t M a n a g e r

D e r r i c k H EN D RY – Pe l i c a n s u bs u r f a c e t e a m l e a d

Pe l i c a n s u bs e a r e -d e v e l o pme n t 2010

- w h a t w e n t r i g h t ?


Pelican: a 2008 acquisition by TAQA

• NNS assets acquired from Esso/Shell (100% operator)

• Mature waterfloods near abandonment

• TAQA’s business plan• Make it safe and work… then grow

• Water injection re-instatement + infill drilling

• Invest on Pelican?• Large volume, deep Brent formation

• Underperforming, low recovery. Potential ?

• Subsea. Capital ranking ?

• Decision to pursue the Pelican redevelopment opportunity


Location


TAQA’s 2010 mobile drilling campaign

• Stena Spey rig• Re-enter and sidetrack PU-P10bs2

• Drill new well PU-P20• Fix integrity PU-P18

+ Diving Vessel Osprey• Inspection

• Hook-up PU-P20

PU-P18

Live producer - vertical

Live producer - lateral

Live injector - lateral

TOP BRENT MAP

Abandoned producer - vertical

Abandoned producer - lateral

Abandoned injector - lateral


Pelican Geology

• West dipping fault block

• OIIP 550 to 600 mln stb

• BRENT formation• 10,500 to 12,150 ft ss

• Heterogeneities

• Diagenetic imprint, depth related

• Depositional facies + preservation

Two controls: stratigraphy and depth


Pelican Structure & faulting

Top Brent TWT Map


Pelican initial development

• 1996 subsea tie-back to Cormorant Alpha

• Water injection• Operating 4500 psi reservoir

compared to 7300 psi initial

• Undersaturated oil 36 API, 600

scf/stb, Pb=2340 psi

• 16 wells drilled• Vertical crestal wells to complex

“designers”

PU-P18

Live producer - vertical

Live producer - lateral

Live injector - lateral

TOP BRENT MAP

Abandoned producer - vertical

Abandoned producer - lateral

Abandoned injector - lateral

PU-W11 Injector Trajectory


Production performance - Observations

• P.I. drops

• Liquid production and

injection decline

• Zonal isolation issues

• Well stock down since 2007

Oil 63 mmstb(11% recovery factor)

Water 17 mmbblWater Injected 70 mmbbl


Appraise Phase: Opportunity Identified

• We reshaped and history-matched model

• Geological model: remap properties

• Eclipse: upscale the million cell

model to regain control…

“Complexity is no accuracy”

• Our conclusions supported by many observations

• Lower Brent virtually un-swept

• Upper Ness thief zone

As…

• Permeability contrast

• Flow units vertically isolated

• Cross-faults communication model

was key

Slide 13

Upper Ness

Mobile oil thickness (ft)

Initial 1996

Current 2009

End of field life 2026Case: No Further Investment

Slide 19

Lower Ness and Etive

Mobile oil thickness (ft)

Initial 1996

Current 2009

End of field life 2026

Case: No Further Investment

Un-developed mobile oil THICKNESS


Concept/Select: understand subsea options

• 2x8” Production Flowlines

• 8” Water Injection Flowline

• 6” Gas lift Flowline

• 8 Production Wells

• 2 Water Injection Wells

• 5 tie-in points possible • Including abandoned P10

(flowbase connected)

• Including new daisy chain to P19

• 2 spare gas lift points

• New wells: new SCM


Summary: an integrated selection phase

• “strategy matrix” approach

• Retained• Make it safe: P18 intervention

• Make it work: zonal isolation is KEY, simple well architecture, near vertical

• Make it grow: include two new wells in programme

Option Decision

Production /

Reserves

Costs

down

Value of

info.

Risk

acceptable

HSE /

Integrity

Equipment

lead times

Weather

window

CA

shutdown

Sim. Rig

/diver ops

Programme

New producer S/T from P10 � � � � �

New producer daisy chain to P19 � � � � �

P18 WO or S/T � � �

P14S1 G/L valve + flowbase � � �

P13S1 G/L choke � �

Proposed sequence order � � � � � � � �

Optional

P19 reperforation � option �

W17 insert valve � option �

W11 insert valve � option �

Alternatives considered

Drill one injector � � � �

P15 S/T new well � �

P14S1 S/T new well � �

S/T P16S1 to new well � � �

Idem P11, P12S1 � � �

S/T from W12 �

S/T from P15 � �

Aband. P15 and use tree � �

S/T from P14 � �

New slot near P10 for new prod. � �

Drill Pelican before Tern � � �

Move P16S1 at end sequence � �

Move P18ST at end sequence � � � � �

Drill New Prod first � �

(Wells or subsea)

(Project & Sequence)

Criteria for decision

NPV or Value Constraints

(Subsurface)

OPTIONS

CRITERIA (for given strategy)

Retained

Alternatives


Execution: on budget


Deviations from plan, issues

• Operations• Tight planning: wow, long lead items, planned platform shut down…

• One opportunity cancelled

• Rig skid back and forth to P20

• HSE

• 1 LTI

• 1770 potential incidents prevented

• P10bs2 produced… rubber and a bit of water, too

• Challenges ahead• Flowline bottlenecks

• Well productivity declines understanding still in progress

• Declining economics versus… unpredictable tax regime


The outcome: Pelican Field Oil Rate

Pelican 2010 Performance

0

2000

4000

6000

8000

10000

12000

14000

01-J

an-1

0

01-F

eb-1

0

01-M

ar-10

01-A

pr-10

01-M

ay-1

0

01-J

un-1

0

01-J

ul-10

01-A

ug-1

0

01-S

ep-1

0

01-O

ct-10

01-N

ov-1

0

01-D

ec-1

0

Oil r

ate

(stb

/d)

Actuals

Monthly Aver

Budget

New well

PU-P10s2

Platform

Planned

shutdown

New well

PU-P20


Proof of Concept: P10bs2 and P20 logs

Swell Packers Proposed Initial Perforated IntervalSwell Packers Proposed Initial Perforated Interval

Swell Packers Proposed Initial Perforated Interval DFT Formation Pressure DepthsSwell Packers Proposed Initial Perforated Interval DFT Formation Pressure DepthsSwell Packers Proposed Initial Perforated Interval DFT Formation Pressure Depths


Lessons Learned

• “Keep it simple”: a strategy from concept to execution

• Flow unit based reservoir description

• Near vertical wells reduce costs and

risks

• Swell packers• Zonal isolation achieved

• Manage long lead delivery time• Longer forward planning, approval

and procurement process needed

P10bs2 - swell packers completion


Conclusion: success factors

• Organisational: a Project Management and Value Assurance system adapted to risks and uncertainties of our industry

• People: to fit the project. NB “Sponsors” & Reviewers

• Added value through reservoir (and change) management

• Execution: pragmatic, fold-back solutions

No compromise: well integrity first


Thank You

• To the Audience for your attention

• To the people of TAQA, Senergy, Wood Group, JP Kenny, Stena, ADIL and all Contractors that have participated to the 2010 mobile drilling campaign

Next on DEVEX AgendaNewburgh Golf Course / Ythan estuaryfield trip this evening

Backup slides if questions


Pelican Field Oil Rate, past 10 years

Pelican Field Oil Rate

0

5000

10000

15000

20000

25000

01-J

an-0

0

01-J

an-0

1

01-J

an-0

2

01-J

an-0

3

01-J

an-0

4

01-J

an-0

5

01-J

an-0

6

01-J

an-0

7

01-J

an-0

8

01-J

an-0

9

01-J

an-1

0

Oil R

ate

(stb

/d)


Production from new wells (stacked)

0

2000

4000

6000

8000

10000

12000

14000

September-10 October-10 November-10 December-10 January-11 February-11 March-11 April-11

bo

pd

P10bs2 P20

P20 completed after seasonal Cormorant Alpha shut-down


Pelican well design: plan for success

• Well trajectory: ideally long horizontal wells• Historically took 180 days to drill, and difficult to cement• TAQA: “sacrifice some inflow performance for drilling success”

• deviated wells

• swelling packer isolations (more control)

• Result:• 2 producers added• >10,000 bopd added• Dry oil to date

• Learnings:• Keep it simple if possible

0

30

60

90

120

150

- 10 20 30 40 50 60 70 80 90

Rushmore Complexity Index

Days

Other North Sea operators

TAQA

Tern North

(H-block)

PU-P20

Presented at 2011 Offshore Production Summit


TAQA NNS story so far – versus “Apache Forties”

Compare TAQA NNS versus Apache Forties

-

10,000

20,000

30,000

40,000

50,000

60,000

Last year

previous operator

Year 1 Year 2 Year 3

NN

S o

il p

rod

ucti

on

(b

/d)

.

-

20,000

40,000

60,000

80,000

100,000

120,000

Fo

rties o

il pro

du

ctio

n (b

/d)

TAQA NNS Operated fields

Apache Forties

TRANSITION

OPERATORSHIP

Equivalent

production levels

in last year

Apache needs

big shutdowns

Same

decline

trend

Presented at 2011 Offshore Production Summit


Reservoir match : global parameters only

Field History-Match

Oil Rate / Liquid Rate

Watercut

Cumulative Oil

BHP / THP

Typical match quality: P11


Tree options

• Many constraints e.g. incompatibility Vetco/Cameron

• 10 options identified• E.g. selected: order Cameron tree, set on P10, retrieve P18 tree and refurbish,

re-run spare on new well

Vetco Cameron

PU-P18PU-P18 PU-P19

PU-P11

PU-P15

PU-P12 PU-P13 PU-P14

PU-P16 PU-W11

PU-W17

Pelican

PU-P14

PU-P10

PU-W17

PU-W12

Closed. Well available

Closed, well not available

WellheadWell open

Tree

SparesSpare Prod Spare WI


Value Assurance & Project Milestones

• “Framing Session”: Aug 09

• Budget 2010: Aug 09

• TAQA Functional Heads reviews: Sep and Nov 09• + Reservoir Engineering peer review

• Decision Review Board: 24 Nov 09• Long Lead orders

• Kick-Off Define Phase: Dec 09

• Value Assurance Review : Feb 10

• Rig on Pelican: May 09

• First Oil: Sep 10

taqa pelican devex 2011 · 2012-04-14 · taqa bratani devex 2011 – aberdeen - thursday 12 may...

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