DOC ID© Chevron 2005

Offshore field experience with BrightWater

Presenter: Nancy LugoChevron Upstream Europe

Stavanger 20/01/2010

Team Members:Nancy Lugo, David May, Elaine Campbell – Chevron Upstream Europe, AberdeenRick Ng, Steve Cheung – Energy Technology Company, Houston, Texas

2

Agenda

•What is BrightWater

•Applications in the world

•BrightWater in Strathspey

•Strathspey field and geology

• BrightWater treatment in Strathspey

•Modeling process

•Treatment execution

•Results

•Lessons Learned

•Conclusions

3

What is BrightWater

• Novel particulate system for in–depth waterflood conformance control

• Co-developed between Chevron, BP and Nalco

• Small cross-linked polymer particles bullheaded into injection well

• Propagate deep into the reservoir

• Once heated polymer expands to block pore throats and prevent further fluid flow through rock

• Injected water diverts into less swept zones

4

BrightWater applications

STC

• 2001

Minas Field – Indonesia (Chevron operated)

• Extra oil observed (SPE

84897)

• 2002/03

Arbroath, North Sea (BP)

No extra oil. Ownership changes & production issues stopped assessment of field benefit.

• 2004/05

Alaska - Milne Point & Prudhoe Bay (BP)

• Over half a million extra barrels recovered from four trial wells. Treatment cost of just $3.20 - $3.80 per barrel.

• 2006

Strathspey

• Over 130 mboe increase first 12 months. Treatment cost of $3.5 - $4 per boe.

Horn Mt 2006

Arbroath 2002

Minas 2001

Kotabatak 2006/07

BW for carbonates

Milne Pt 2004

Prudhoe 2004/05 (3)

NWFB 2005 (2)

Strathspey

2006

Tangri 2006

Barrow IslandPanAm 2006

Completed Planned Development

Horn Mt 2006

Arbroath 2002

Minas 2001

Kotabatak 2006/07

BW for carbonates

Milne Pt 2004

Prudhoe 2004/05 (3)

NWFB 2005 (2)

Strathspey

2006

Tangri 2006

Barrow IslandPanAm 2006

Completed Planned Development

Brightwater treatment in Strathspey Field

Upper Brent

Reservoir

Brent

Statfjord

Triassic

Dunlin

Upper Brent

ReservoirLower Statfjord

Reservoir

W

• Subsea development

• Consists of a tilted fault block (10° West)

• Two Reservoirs

• Brent Group (Black Oil)

• Banks Group, Statfjord Fm. (Gas Condensate)

• Production Mechanism

• Brent: water flooding, best candidate for

BrightWater application

• Statfjord: depletion drive

• Brightwater deployed in Brent reservoir

Original OWC -9380ft TVDSS

1000ft

1km

Top B1Top B2

Top B3

Top B4

Top B5

Top B6

Top B7

Top

Dunln

W E

BC

D GR

F2d

ER

M6 Injector MS9

Main Field Reservoir Units Dip 10° West

Reworked Rotated Fault Blocks

M10 MS19

LogSection

6

Strathspey Brent Geology

• Favorable mobility ratio has led to efficient sweep in general – Main Field wells

• Geological heterogeneity and complex faulting in the slumped areas has led to localized early water breakthrough and poorer waterflood efficiencies.

Top Brent Depth Structure

1km

Brent

Central

Brent

South

MS19

MS9

M10

M6

MS14

M5 M11

12

M3

5

M7

M15zM9

MS14 as candidate for BW treatment

•Fast watercurt development at MS19

after MS14 injection started

•Reservoir simulation indicated high oil

saturation around MS19.

•Conventional water shut-off methods

require well intervention

• Cost prohibitive in a subsea environment

• BrightWater treatment recommended

for well MS14

• Treatment deployed in September 2006

MS19 Cumulative Plot 2003

For Every 100 RBW Produced

0

500000

1000000

1500000

2000000

2500000

3000000

3500000

4000000

0 500000 1000000 1500000 2000000 2500000 3000000 3500000

Cumulative RBW Produced

Cu

mu

lati

ve R

BO

Pro

du

ced

227rbo

111rbo53rbo

18rbo

Top Brent Depth Structure – MS14 to MS19

Brent

Central

MS19

MS9

M10M6

MS14

M15zM91km

Top Brent Depth Structure – MS14 to MS19

Brent

Central

MS19

MS9

M10M6

MS14

M15zM91km

Cross Section 1

Cross Section 2

EW

Cross Section 2

-9380ftTVDSS OWC

B5

B3

Main Field Rework

250m

MS19

Rework Fault

Cross Section 1 - along MS19 Well Path

Cross Section (W-E) along MS19 well path•Reworked fault blocks

•Faults act as baffles not sealing

•M6 injector give underlying support but not enough direct

support within the fault compartments

•MS14 considered a good injector candidate as it could sweep

north towards the faulted compartments

•Hard to get efficient sweep in this area

Top Brent Depth Structure – MS14 to MS19

Brent

Central

MS19

MS9

M10M6

MS14

M15zM91km

Cross Section 1

Cross Section 2

MS14

NS

MS19

-9380ftTVDSS OWC

B5

ReworkFault

250m

MainField

Rework

Cross Section 2 - MS14 to MS19

•N to S fault structure indicates channeling was likely

•Perm differences between layers indicated thief zones

were likely

•Possible improved vertical sweep efficiency was a target

•MS14 was proposed as target for BW

Cross Section MS14 to MS19

High Perm Layer

Layer 7: grid blocks in the main area are 125ftx125ft so 700ft is cooled towards MS19

MS14

MS19

intersecting

Layer 7

Flank

injector

10

Modeling Process – BrightWater

STC

Cooling around MS14

Tracer in Layer 7 thief: 3 months after injection

Layer 7 (part of B5):

Black lines show position of sealing or part-sealing faults

Extent of open perfs in MS19

MS14

Temperature regime around injector

•Use tracer • Determine well-well transit time and temp (help select best grade for the application) • Look at where the bulk injected BW would go

Temperature Profile Tracer Concentration

Bulk BW would go –Thief layer

11

Modeling Process BrightWater (cont…)

STC

Determine BrightWater Grade using Lab Tests

• Check activation times using bottle tests

• Inject selected BW grade into sand packs to check

activation time/strength

• Calculate Resistance Factor

• Reservoir core test to select optimum formulation

12

Modeling Process BrightWater (cont…)

STC

Layer 7: grid blocks in the main area are 125ftx125ft so 700ft is cooled towards MS19

MS14

MS19

intersecting

Layer 7

Flank

injector

Predict Incremental Oil

•Run full waterflood history match

•Reduce permeability in the model at the

position reached by tracer after heating

•Rerun tracer (assess if water takes a different

route)

•Predict oil recovery with and without BW

•Predict incremental oil

•Calculate required treatment quantity

BW - Total Incremental: 250 - 500 mboe

13

Treatment Execution

STC

STRATHSPEY SUBSEA LAYOUT

_________________________________

BRENT 'A'BRENT IGLOO

BRENT RECEIVERTEE STRUCTURE

16" WELGAS PIPELINE

BRENT 'A'BRENT IGLOO

BRENT RECEIVERTEE STRUCTURE

16" WELGAS PIPELINE

GAS EXPORT

SSIV/LAUNCHER

SUDS

SSIV UMB.

TEXACO SSIVPROTECTION

STRUCTURE

16" GAS EXPORT

NINIANCENTRAL

NINIANSOUTHERN

E/H CONTROLS

12" WATER INJECTION

SATELLITE WELLSMS9(B) & MS14(B)

'F' CLUSTER WELLS

'A' CLUSTER WELLS

M6

(WI)

M2Z(S)

M3(B)

M5(WI)

M1(S)M10(B)

M4(S)

M9(B)

M7(B)M8(S)

Manifold

Gas to St

Fergus via

FLAGS system

Liquids to

Sullom Voe

through

Ninian

pipeline Water injection

from Ninian

South

2 Brent lines, 2

Statfjord lines,

methanol and utilities

lines

Fore and aft cluster wells

Satellite wells

MS14 INJECTOR

Brightwater Treatment - Logistics

• Planned

140,000 litres Brightwater

70,000 litres BW Surfactant

Spiked to 58,000 BBL Injection Water

1.5% Polymer Concentration

Pump Time at 22,000 bpd (15bpm)

2.7 DAYS

• Actual

Metering Error

First Half Of Polymer Treatment At 1%

Second Half At 1.5%

15

Results

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

2,000

3,000

4,000

5,000

6,000

7,000

8,000

5,000 7,000 9,000 11,000 13,000 15,000 17,000 19,000

Wa

tercu

t

Oil R

ate

(b

op

d)

Total Fluid Rate (bpd)

MS19 Pre and Post BW1

bopd 2003 bopd 2007 %wtcut 2003 %wtcut 2003

• In 2007 the watercut appeared to be

more controlled.

• Under similar voidage replacement

conditions water cut accelerated to 80%

over a matter of nine months in 2003

• BrightWater® slowed down the passage

of water considerably between injector

and producer.

• Allows MS19 to flow naturally at higher

fluid rates with lower water-cut. MS19 Production History

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

19/1

2/2

001

19/0

6/2

002

19/1

2/2

002

19/0

6/2

003

19/1

2/2

003

19/0

6/2

004

19/1

2/2

004

19/0

6/2

005

19/1

2/2

005

19/0

6/2

006

19/1

2/2

006

19/0

6/2

007

BO

EPD

Base BOE Inc BOE

• Data indicated oil production rise of 575

boepd.

• Incremental of 130 MBOE first year

• Total incremental hydrocarbon estimated

to rise to 317,300 boe

Best Practices and Lessons Learned

Best Practices.

• Committed cooperative efforts among operators, vendors and research

insititutes can deliver innovative technologies for enhancing hydrocarbon

recovery.

• Investigate all data available to determine transit time between injector and

producer. Consider an interwell tracer test first if there is a chance of very rapid

connection between wells

• Simple simulation studies add valuable insights to the design and provide useful

estimation of incremental oil recovery.

Lessons Learned.

• Long term operator commitment is needed assign resource, monitor results and

document.

• Failure of of crucial subsea equipment can make monitoring of well performance

very difficult for long periods until opportune availability of vessels is possible.

• More thorough yard trials for pumping Brightwater should be conducted with the

vendor and operator personnel present.

16

Conclusions

Brightwater was successfully deployed via a 10 mile

subsea water injection line from the Ninian South

Platform

The treatment reduced the rate of water injection

channeling between injector MS14 and producer MS19.

The impact on MS19 is that the well can produce at a

higher total fluid rate with a lower watercut leading to

increased oil production.

Incremental oil delivered in the first 12 months is

130,000 boe.

17

18

STC

Any questions?