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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Timber Creek Field Study for Improving Waterflooding
Shaochang Wo Gillette, Wyoming
June 4, 2014
The 2nd Minnelusa Workshop of EORI
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Project Summary and Timeline
• A collaborative study between EORI and Merit Energy Company under the Minnelusa Consortium
• The primary objective of the project is to evaluate various development plans for improving the waterflooding in its Minnelusa Reservoir
• The Timber Creek Field Geologic Study was completed by Gene George in Feb. 2010
• The Modeling and Simulation Study was started in Nov. 2009 and a final report was submitted to Merit in Feb. 2011
• A new injector was drilled in late 2011, named Gene George #1, and water injection initiated in Oct. 2012
• Monthly oil production has risen to 36,317 STBO/month in Aug. 2013 from 16,800 STBO/month in Feb. 2010
• Updated the TC model in late 2013 to include GG #1. Extended history matching and production forecast was performed
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Oil and Gas Fields in Wyoming Basins
Powder River Basin
Greater Green River Basin
Bighorn Basin
Wind River Basin Overthrust
Belt
Hanna Basin
Laramie Basin
Jackson Hole
Denver Basin
Shirley Basin
Areas with oil producing Minnelusa reservoirs
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Minnelusa Reservoirs in the Northern Powder River Basin
Timber Creek Field (T49N R70W)
Gillette
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Depth of Minnelusa Top 9100 ft Initial Reservoir Pressure 3655(B), 3629(C) psi
Average Core Porosity 13.8(B)%, 11.1(C)% Oil Gravity 31(B), 27(C)o API
Average Core Permeability 77(B) md, 47(C) md Bubble Point Pressure (BPP) 770(B), 599(C) psi
Average Gross Pay 60(B) ft, 50(C) ft Gas Oil Ratio at BPP 85(B), 65(C) SCF/STB
Average Net Pay 34.4(B) ft, 21.7(C) ft Est. OOIP 35(B), 20(C) MMBO
Oil Column 125(B), 118(C) ft Cum. Oil Production 14(B), 6(C) MMBO
Oil/Water Contact Various Oil Recovery 40(B)%, 30(C)%
Reservoir Temperature 204o F Well Spacing 40 acre
Primary Drive Mechanism Water and solution gas Est. CO2 MMP 3500 psi
Oil and Reservoir Properties of the Minnelusa Reservoir at the Timber Creek Field
(B): B Sand (C): C Sand
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Geologic Model (Petrel)
Simulation Model (Eclipse, CMG)
History Matching
Evaluation of EOR/IOR Floods
Description of Reservoir Structure & Faults Rock Facies & Flow Units Fracture Network & Connection
Well Logs Well Completions Core ɸ, K, Sw, So Seismic Survey
3D Grid System ɸ & K of Grids Initial So, Sg, Sw
Remaining oil Distribution in Reservoir
Reports & Recommendations
Operator Requests
Laboratory Data Fluid & Rock Properties: PVT, Kro, Krw, Krg, …
Production & Injection History
Typical Workflow in Reservoir Modeling & Simulation
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E Minnelusa Top and Possible Faults at Timber Creek Field - By Gene George
?
?
CROSS SECTION LINE
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Three B Sand Units (Sand Compartments) Identified by Gene George
RED = UPPER HIGH RESISTIVITY (>10 OHMS) BLUE = MIDDLE LOWER RESISTIVITY (<10 OHMS) GREEN = LOWER LOW RESISTIVITY (<3 OHMS)
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Model Boundary
The Model Boundary and the Three B Sand Units Mapped by Gene George
Aquifer Water Influx
Aquifer Water Influx
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
1 mile
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
What A Simulation Model Needs from A Geologic Model
• A structured grid system of the reservoir — It is desirable to configure flow units, e.g. sand
compartments, as layers in the grid system • Rock/formation properties of grids
— Such as porosity and permeability • Initial oil, gas, and water saturations of grids
— Commonly estimated from Archie relations
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
12
9150
9200
9250
9300
9350
9400
0.00 0.50
F. E. COOK #1
9100
9150
9200
9250
9300
9350
0.00 0.50
F. E. COOK #2
9000
9050
9100
9150
9200
9250
9300
0.00 0.50
F. E. COOK #3
9100
9150
9200
9250
9300
9350
0.00 0.50
F. E. COOK #4
9000
9050
9100
9150
9200
9250
9300
0.00 0.50
F. E. COOK #5
9000
9050
9100
9150
9200
9250
9300
9350
0.00 0.50
FED 311 CAMPBELL #1
9100
9150
9200
9250
9300
9350
9400
9450
0.00 0.50
FED 311 CAMPBELL #2
9200
9220
9240
9260
9280
9300
0.00 0.50
LE SUEUR #3-S
9100
9150
9200
9250
9300
9350
9400
0.00 0.50
LE SUEUR #2-S
Porosity
Water Saturation
10*(Bulk Volume Water)
B Zone Perforation
C Zone Perforation
Measured core porosity and water saturation in Cook, LeSueur and Campbell wells
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
13
9000
9050
9100
9150
9200
9250
9300
0.00 0.50
V. H. WOLFF #1
9100
9150
9200
9250
9300
9350
0.00 0.50
V. H. WOLFF #2
9100
9150
9200
9250
9300
0.00 0.50
V. H. WOLFF #3
9100
9150
9200
9250
9300
9350
0.00 0.50
V. H. WOLFF #4
9100
9150
9200
9250
9300
9350
9400
0.00 0.50
V. H. WOLFF #5
9200
9250
9300
9350
9400
9450
0.00 0.50TORO #1
9100
9150
9200
9250
9300
9350
0.00 0.50TORO #2
9200
9250
9300
9350
9400
0.00 0.50TIMBER CREEK USA #2
9100
9150
9200
9250
9300
9350
0.00 0.50
TIMBER CREEK USA #1
Porosity
Water Saturation
10*(Bulk Volume Water)
B Zone Perforation
C Zone Perforation
Measured core porosity and water saturation in Wolff, Toro and TC USA wells
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
B Sand Blue
B Sand Red
B Sand Green
B Dolomite
Upper C Sand
Middle C Sand
Lower C Sand
B Region
Upper C Region
Lower C Region
B Dolomite Region
The 7-layer and 4-region Configuration of the Simulation Model for the Minnelusa Reservoir at Timber Creek Field
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Making Sand Units in Petrel
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Loading Log and Core Measurements in Petrel
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Modeled Minnelusa Structural Top at Timber Creek Field
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
A 3D View of the Layer and Grid Configuration
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Grid pore volume distributions in the Red (top left), Blue (top right) and Green (bottom right) units of the B Sand.
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Grid pore volume distributions in the Upper (top left), Middle (top right) and Lower (bottom right) units of the C Sand
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Core Porosity-Permeability Correlation within Each Layer
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
A 3D View of the Porosity Distribution in the Model
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
A 3D View of the Permeability Distribution in the Model
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Original Questions set for History Matching
• What would the initial oil-water contacts be in the B and C Sands and where does the oil remain today?
• How much is the C Sand contribution in the total oil production of wells that have commingled production from both B and C Sands?
• Can a good history matching be achieved without assuming fault-separated compartments?
• Aquifer water influx, from where and how much? • How does fluid move among the 3 pods in the B
Sand? • Any infill drilling opportunities?
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Some Data Issues in the History Matching
• A few BHP or fluid level measurements • No gas production record before 1975 • About 2.8 million barrels of oil produced
without gas producing records between 1975 and 1998
• Gaps in water producing records • Only partial PVT report of the C sand oil • No data of laboratory measured relative
permeability
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
100
1,000
10,000
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005
Aver
age M
onth
ly Ra
tes
0
5
10
15
20
25
No of
Pro
ducin
g Well
s
bopdbwpdbWINJpdWell Count
End of WF (IWR < 1.0)
Period of IWR > 1.0
Timber Creek Field – Production History. This figure is copied from “Timber Creek Field: Exploitation Review”, an internal report of Merit Energy Company by Brad Bauer
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
1
10
100
1,000
10,000
100,000
Jan-57 Jan-67 Jan-77 Jan-87 Jan-97 Jan-07 Jan-17
Mon
thly
Oil
Prod
uctio
n Ra
te, B
O/m
onth
Cook 1
Cook 2/2R
Cook 3/3R
Cook 4
Cook 5
Fed 311 1
Fed 311 2
LeSueur 1
LeSueur 2
LeSueur 1-S
LeSueur 2-S
LeSueur 1-M
LeSueur 2-M
LeSueur 3-M
TC USA 1
TC USA 2
Toro 2
Toro 3
Toro Fed 23-6
Wolff 1
Wolff 2
Wolff 3
Wolff 4
Wolff 5
Well monthly oil production rates at Timber Creek Field
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
1
10
100
1,000
10,000
100,000
Jun-57 Aug-61 Sep-65 Oct-69 Dec-73 Jan-78 Feb-82 Mar-86 May-90 Jun-94 Jul-98 Sep-02 Oct-06 Nov-10
Mon
thly
Wat
er P
rodu
ctio
n Ra
te, B
W/m
onth
Cook 1
Cook 2-2R
Cook 3-3R
Cook 4
Cook 5
Fed 311-1
Fed 311-2
LeSueur 1
LeSueur 2
LeSueur 1S
LeSueur 2S
LeSueur 1M
LeSueur 2M
LeSueur 3M
TC USA 1
Toro 2
Toro 3
Wolff 1
Wolff 2
Wolff #3
Wolff 4
Wolff 5
Well monthly water production rates at Timber Creek Field
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 1
10
100
1000
10000
100000
Mar-60 Sep-65 Mar-71 Aug-76 Feb-82 Aug-87 Jan-93 Jul-98 Jan-04 Jul-09 Dec-14
Mon
thly
Wat
er In
ject
ion
Rate
, BW
/mon
th Fed 311-1
Fed 311-2
LeSueur #31-17
LeSueur #1-S
LeSueur #2-S
LeSueur #2
LeSueur #3-M
LeSueur #5
TC USA #2
Wolff #2
Wolff #3
Wolff #5
Well monthly water injection rates at Timber Creek Field
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Well Cumulative Production and Injection, as of June 2010
3 M
MBW
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Krw
and
Kro
Water Saturation, fraction
Timber Creek Minnelusa: Pseudo Relative Permeability from History Matching
Kro for B and C Sands
Krw for B Sand
Krw for C Sand
Sor = 0.3 Swr = 0.2
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Observed (orange line) and simulated (green line) monthly rates of the field oil production
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Simulated reservoir average pressure (black) plotted with simulated (red) and reported (green) field GORs
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Simulated and reported cumulative field water productions
Simulated and reported field water production rates
Simulated Reported
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Fence diagram showing the initial oil saturation distribution in December 1962 (top) and the predicted oil saturation distribution in June 2010 (bottom) after history matching
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Findings from History Matching
• Drill-stem tests and oil PVT measurements reveal that the B and C Sand traps are separated oil systems.
• Mobile water initially existed in the C Sand pay intervals but almost no initial mobile water was in the B Sand pay intervals.
• The original oil-water contact in the B Sand varied from -4620 to -4714 feet subsea, trending higher in the southeast portion of the field and lower along its northwest flank. Tilted oil-water contacts were also observed in the C Sand, with a trend similar to the variation in the B Sand, and estimated to vary from -4721 to -4797 feet subsea.
• Both B and C Sands are producing under aquifer water drive, where the C Sand has more significant water influx support. The cumulative water influx into the B Sand, Upper C Sand unit and Lower C Sand unit are estimated to be 5.1, 3.3 and 7.9 MMBW, respectively.
• The B Sand volume in the static model derived from existing well controls appears to be smaller than the actual sand volume. In the history matching of the initial depletion, the pore volume of the B Sand had to be increased by 20% at the northern quadrant and 10% elsewhere to uphold a sustainable pressure decline.
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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E
Findings (cont’d)
• The resulting relative permeability curves from history matching indicate that the Minnelusa reservoir rock at Timber Creek Field is strongly water-wet.
• The lateral permeability in the B and C Sands was increased by a factor of 2 to 5 during the history matching to maintain the observed production rates. The increase in total permeability is most likely contributed by fractures, whereas the initial permeability distribution is estimated for matrix permeability only.
• A west-east fault may exist between Toto #1 and Toro #3. Both wells were perforated in the same B Sand unit with high resistivity. Toto #1 is wet but Toro #3 has produced very little water. Because Toto #1 was not included in the history matching, therefore, the effect of this conceivable fault was not evaluated in the simulation.
• Because of insufficient water injection volume during the production period between 1979 and 1998, the average reservoir pressure dropped below the bubble point pressure and caused very high producing GOR.
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Findings (cont’d)
• Evident production response to cross-pod injectors suggests that the three B Sand bodies are at least partially connected. No any part of the field could be identified as a self-balanced production-injection region.
• The OOIP in the B Sand is estimated to be 35.4 MMBO, in which 13.9 MMBO have been produced, as of June 2010, a recovery rate of 39%.
• For the C Sand, the estimated OOIPs in the Upper and Lower sand units are 6.1 and 13.9 MMBO, respectively.
• There is some uncertainty in the estimation of OOIP for the C Sand, particularly for the Lower sand unit, due to limited well controls. It is estimated that 2.5 MMBO, or 41% of its OOIP, have been recovered from the Upper C Sand unit. In contrast, only 3.5 MMBO have been produced from the Lower C Sand unit with a much lower recovery rate of 25%. The entire C Sand contributed about 30% of the field total oil production.
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(Producer/Injector)
Location of A Vertical Development Well Proposed by Merit
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Location of A Horizontal Development Well Proposed by Merit
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• Case 1 (base case): 40-year production under current production-injection scheme
• Case 2: drill a vertical production well • Case 3: drill a horizontal production well • Case 4: increase injection volume • Case 5: reactivate Wolff #3 • Case 6A: convert Cook #1, Cook #4 and Wolff #1 to
injectors • Case 6B: Case 6A + converting Cook #3R to injector • Case 7A: drill a new injector • Case 7B: Case 7A + converting Cook #3R, Cook #4 and
Wolff #1 to injectors
Simulated Development Scenarios
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Field Daily Oil Rates of the 9 Simulated Scenarios
Case 7B with A new Vertical Injector
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Field Cum. Oil Productions of the 9 Simulated Scenarios
Case 7B with A new Vertical Injector
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Estimated Oil Recovery of the Simulated Scenarios (the best case in each category is highlighted in green)
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Initial Isopach Maps of the Three B Sand Units - from Gene George
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Updated Isopach Map of the Middle B Sand Unit - from Gene George
Simulated Well Location
GG #1 Well Location
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GG#1 Perforation Top
GG#1 Perforation Bottom
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0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
Jul-09 Nov-09 Mar-10 Jul-10 Nov-10 Mar-11 Jul-11 Nov-11 Mar-12 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14
Wat
er C
ut, f
ract
ion
Mon
thly
Oil
Prod
uctio
n Ra
te, B
O/m
onth
Timber Creek Field: Monthly Oil Rate and Water Cut (since Jan. 2010)
Field Oil Rate Simulated Oil Rate of Case 7B Field Water Cut
Water Injection initiated in Gene George #1 in Oct. 2012
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Water Injection Status in June 2010, Case 7B, and June 2013
Well Name Well Status Ave. Daily Injection Rate in June 2010
June 2010 BWIPD GENE GEORGE # 1 Cook # 1 Shut -in Cook # 3R Producer Cook # 4 Producer Fed 311 Camp # 1 Injector 1332 LeSueur # 2-S Injector 1003 LeSueur # 3-M Injector 160 Wolff # 1 Shut -in Wolff # 3 Shut -in Wolff # 5 Injector 360
Total water injection 2855
Well Status Targeted Injection
Rate in Case 7B June 2010 BWIPD
Injector 500 Shut -in Injector 500 Injector 500 Shut -in Injector 500 Injector 400 Injector 500 Shut -in Injector 500
3400
Well Status Ave. Daily Injection Rate in June 2013
June 2013 BWIPD
Injector 600 Injector 318
Producer Shut -in Shut -in Injector 680 Injector 173 Injector 708 Injector 656 Injector 584
3719
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Simulated Oil Saturation on 7/1/2010
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Simulated Oil Saturation on 10/29/2013
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Simulated Oil Saturation on 12/22/2043
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Summary of Updated Model Forecast
• The Timber Creek simulation model has been updated to include the new injector, Gene George #1.
• At the well location of GG #1, B sand top is about 20 ft lower than the previously modeled B top. However, the model is still suitable for simulating the water injection of GG #1 because of its lower elevation at structure downdip.
• As indicated from history matching, there is no clear barrier to fluid communication between the B Red and B Blue sand bodies in the northern quadrant of the field.
• The field may already have seen its new peak oil. However, a moderate decline in oil rate is predicted that could sustain an average production over 1000 BO/day for the next four years.
• Under current production-injection configuration, simulation predicts that additional 5.2 million barrels of oil could be produced by the end of 2040.
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Acknowledgments
• We thank Merit Energy Company for providing the Timber Creek field data and allowing us to present the evaluation results.
• We are grateful for Gene George’s help and his in-depth understanding of Minnelusa reservoirs.
• Petrel and ECLIPSE software, a donation from Schlumberger, were used in this study.
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Thank You!