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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
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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
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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.
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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?