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HomeMy WebLinkAbout2010 Greater Kuparuk AreaConocoPhillips
Alaska, Inc.
Greater Kuparuk Area
2010 Annual Reservoir Surveillance Reports
Kuparuk, Meltwater, Tabasco, Tarn, & West Sak
Oil Pools
Reporting Period
January 1 to December 31, 2010
2010
GREATER KUPARUK AREA
ANNUAL SURVEILLANCE REPORTS
Table of Contents
SUMMARY OF EOR PROJECT...................................................................ATTACHMENT
1
Map of EOR Program Status
2
Plot of Incremental EOR Oil Rate
3
PRODUCED FLUID VOLUMES...................................................................ATTACHMENT
2
INJECTED FLUID VOLUMES......................................................................ATTACHMENT
3
PROPOSED PRESSURE SURVEY PLAN
5
RESERVOIR PRESSURE SURVEYS..........................................................ATTACHMENT
4
PROPOSED INJECTION PROFILE SURVEY PLAN
INJECTION SURVEY DATA........................................................................ATTACHMENT
5
PRODUCTION SURVEY DATA...................................................................ATTACHMENT
6
MISCIBLE INJECTANT COMPOSITION.....................................................ATTACHMENT
7
CPF1 MI Composition
CPF2 MI Composition
KUPARUK LSEOR DEVELOPMENT PLAN .................................................ATTACHMENT
8
GKA 2010 SHUT-IN WELL REPORT..........................................................ATTACHMENT
9
SUMMARY OF EOR PROJECT & RESERVOIR MANAGEMENT ...............ATTACHMENT
1
PRODUCED FLUID VOLUMES...................................................................ATTACHMENT
2
INJECTED FLUID VOLUMES......................................................................ATTACHMENT
3
PROPOSED PRESSURE SURVEY PLAN
RESERVOIR PRESSURE SURVEYS..........................................................ATTACHMENT
4
PRODUCTION & SPECIAL SURVEYS........................................................ATTACHMENT
5
WELL ALLOCATION & SHALLOW GAS SPECIAL MONITORING... ..........
ATTACHMENT 6
Meltwater OA Pressure Survey for 2010
MELTWATER DEVELOPMENT PLAN & OPERATIONAL REVIEW ............
ATTACHMENT 7
MAP SHOWING DEVELOPMENT AS OF 12/31/2010.................................ATTACHMENT
8
TABASCO OIL POOL REPORT
SUMMARY OF EOR PROJECT...................................................................ATTACHMENT 1
PRODUCED FLUID VOLUMES...................................................................ATTACHMENT 2
INJECTED FLUID VOLUMES......................................................................ATTACHMENT 3
PROPOSED PRESSURE SURVEY PLAN
RESERVOIR PRESSURE SURVEYS..........................................................ATTACHMENT 4
PRODUCTION LOGS & SPECIAL SURVEYS.............................................ATTACHMENT 5
WELL ALLOCATION & TEST EVALUATION SUMMARY............................ATTACHMENT 6
FUTURE DEVELOPMENT PLANS..............................................................ATTACHMENT 7
TARN OIL POOL REPORT
SUMMARY OF EOR PROJECT...................................................................ATTACHMENT 1
PRODUCED FLUID VOLUMES...................................................................ATTACHMENT 2
INJECTED FLUID VOLUMES......................................................................ATTACHMENT 3
PROPOSED PRESSURE SURVEY PLAN
RESERVOIR PRESSURE SURVEYS..........................................................ATTACHMENT 4
PRODUCTION LOGS & SPECIAL SURVEYS.............................................ATTACHMENT 5
PRODUCTION ALLOCATION FACTORS ...................................................ATTACHMENT 6
TARN DEVELOPMENT PLAN & OPERATIONAL REVIEW.........................ATTACHMENT 7
MAP SHOWING RECENT DEVELOPMENT WELLS ..................................ATTACHMENT 8
WEST SAK OIL POOL REPORT
SUMMARY OF EOR PROJECT...................................................................ATTACHMENT
1
PRODUCED FLUID VOLUMES...................................................................ATTACHMENT
2
INJECTED FLUID VOLUMES......................................................................ATTACHMENT
3
PROPOSED PRESSURE SURVEY PLAN
RESERVOIR PRESSURE SURVEYS..........................................................ATTACHMENT
4
INJECTION SURVEY DATA........................................................................ATTACHMENT
5
PRODUCTION SURVEY DATA...................................................................ATTACHMENT
6
GEOCHEMICAL OIL PRODUCTION SPLITS..............................................ATTACHMENT
7
PRODUCTION ALLOCATION FACTORS ...................................................ATTACHMENT
8
FUTURE DEVELOPMENT PLANS..............................................................ATTACHMENT
9
KUPARUK GAS OFFTAKE
TABLE OF MONTHLY GAS OFFTAKE.......................................................ATTACHMENT 1
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James T. Rodgers
ConocoPhillips Manager, Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 Kuparuk Oil Pool Annual Reservoir Surveillance Report
Dear Commissioner Seamount,
In compliance with Rule 3, Conservation Order No. 19813, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Unit, is hereby submitting the annual surveillance report on the Kuparuk River Oil Pool.
This report documents the required information pertinent to the field development and enhanced recovery
operations from January through December 2010. The following is an outline of the information provided:
a. A summary of the enhanced recovery project (Attachment 1).
b. Voidage balance, by month, for produced and injected fluids, including low molecular weight
hydrocarbons (Attachments 2 and 3).
c. Analysis of reservoir pressure surveys taken in 2010 (Attachment 4).
d. A tabulation of both injection (Attachment 5) and production (Attachment 6) logs and surveys
analyzed during 2010 from wells in the Kuparuk permit area.
e. Composition of enriched gas injected during 2010 and estimate of MMP (Attachment 7).
f. Kuparuk LSEOR development plan (Attachment 8).
g. 365 days or longer shut in well report for the Greater Kuparuk Area (Attachment 9).
If you have any questions concerning this data, please contact Mark Kovar at 265-6097.
Sincerely,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ATTACHMENT 1
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Summary of the Enhanced Recovery Project
Enhanced Recovery
Miscible water -alternating -gas (MWAG) continues to serve as the main enhanced oil recovery
process for the Kuparuk field. Thirty-one MWAG/IWAG drillsites service the Kuparuk reservoir
which includes 209 available EOR patterns. Some mature patterns generally no longer receive
miscible injectant (MI) but are available for use as lean gas injection wells when plant upsets
occur and when the drillsites are converted to lean gas chase. The field continues to manufacture
miscible injectant at two of its Central Processing Facilities (CPFs). MI manufacture occurs by
blending together produced lean gas and natural gas liquids (NGLs). The NGLs originate from
two sources: (1) the Kuparuk field itself (known as indigenous NGLs), and (2) those NGLs
imported from the Prudhoe Bay Field Central Gas Facility. Importation from Prudhoe Bay is
utilized to fill any shortfall between the total NGL requirement and the available indigenous NGL
production. From a flood management perspective, the majority of available lean gas after fuel
use is blended with these two NGL streams to maximize the daily volume of MI generated in the
field.
During 2010, the MWAG project operated in full MI production mode for most of the 31 MWAG
drillsites. Three mature MWAG drillsites (drillsites 2U, 2V and 2W) continued to conduct lean gas
chase (LGC) tests. The purpose of this lean gas injection, in the format of immiscible water
alternating gas or IWAG, is to recover NGLs left behind by the original MWAG process, and
collect data to evaluate post-MWAG options. The observations from these three drilllsites
indicated potential for increasing returning NGL sales. Drillsites 1A, 1Y and 2X were subsequently
converted to lean gas chase mid -2009, followed by drillsites 1G and 1R later in the year, after
seeing positive response from drillsites 2U, 2V and 2W.
Drillsite 1 D started MI injection in October of 2008 upon completion of an EOR expansion project.
Very positive response of the MI injection has been observed in many patterns in drillsite 1D
during 2009 and 2010. The 2010 annual average incremental oil production rate from drillsite 1D
was 1,736 STB/d.
During the year 2010, Kuparuk imported an average of 17,489 barrels per day of Prudhoe NGLs.
Import NGLs and indigenous NGLs blended with available lean gas generated an average of 167
MMSCFD of MI. The annual average MI injection rate into the Kuparuk Field was 119 MMSCFD.
The remainder was utilized for Greater Kuparuk Area satellite fields, including 31 MMSCFD as
injection and 13 MMSCFD as lift gas in Tarn and Meltwater and 1 MMSCFD as injection at'dNest
Sak. A small amount of MI (2.5 MMSCFD) is used as lift gas in drillsite 3S. West Sak 1J and 1 E
started VRWAG (viscosity reduction water alternating gas) testing and used a tiny amount (-0.3
MMSCFD) of MI. The estimated incremental oil sales in year 2010 from the ongoing Kuparuk
MWAG project were 29.5 MBOPD. As in the past years, due to a lack of baseline water flood
performance data, the incremental oil production from Tarn and Meltwater MWAG is not split from
their total oil.
The priority for gas management at the Kuparuk field during 2010 was to continue to balance
solvent injection between the A -Sand and C -Sand. This maximizes total EOR and returned NGL
rates while avoiding excessive gas production rates, which would cause production impacts due
to gas handling limitations. Total GKA annual average gas production rate in 2010 was 230
MMSCFD, down from 278 MMSCFD during 2009.
MWAG
Small Scale EOR (SSEOR and SSEORX)
Drillsite 2Z continued on MI injection; drillsites 1A, 1Y, and 2X no longer receive MI injection. The
2010 average MI injection rate at Drillsite 2Z was 2 MMSCFD.
Large Scale EOR (LSEOR)
The original LSEOR Drill Sites include: 1 F, 1 G, 1 Q, 1 R, 2A, 2B, 2C, 2D, 2F, 2G, 2H, 2K, 2M, 2T,
2U, 2V, 2W, 2X and 3F. The total MI injection rate into these drill sites averaged 42 MMSCFD in
2010.
EOR Expansions
Expansions to the original LSEOR occurred over multiple phases and now include Drill Sites 1 B,
1C, 1D, 1E, 1L, 36, 3G, 3H, 30, 3Q and 3S. During 2010, the average MI injection rate into
these expansion drill sites was 75 MMSCFD.
IWAG
During 2010 operations, the Kuparuk EOR project continued to maximize the volume of available
MI by blending a majority of available lean gas with Kuparuk-sourced and imported NGL. IWAG
operations were continued in drillsites 1A, 1Y, 2U, 2V & 2W. IWAG at drillsites 1G and 1R was
discontinued in April 2010 after the gas injection line was converted to water injection. These
drillsites will operate with water injection only for the foreseeable future.
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ATTACHMENT 2
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Produced Fluid Volumes
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
MSTB
MMSCF
MSTB
MSTB
MMSCF
MSTB
1
2010
3,168
7,596
15,613
2,151,994
1,646,980
3,233,071
2
2010
2,829
6,585
13,512
2,154,823
1,653,565
3,246,583
3
2010
3,098
7,205
14,417
2,157,922
1,660,771
3,261,000
4
2010
2,967
7,309
14,708
2,160,888
1,668,079
3,275,708
5
2010
2,824
6,972
14,560
2,163,712
1,675,052
3,290,268
6
2010
2,866
6,463
14,685
2,166,578
1,681,514
3,304,953
7
2010
2,875
6,537
14,769
2,169,453
1,688,051
3,319,722
8
2010
2,913
6,599
14,638
2,172,366
1,694,650
3,334,360
9
2010
2,893
6,794
14,270
2,175,259
1,701,444
3,348,629
10
2010
3,061
7,464
15,192
2,178,321
1,708,908
3,363,822
11
2010
2,646
7,059
13,765
2,180,967
1,715,967
3,377,586
12
2010
2,813
7,201
14,444
2,183,779 .`°
1,723,168
3,392,03
2010 TOTAL
34,953
83,783
174,573
Cumulatives at Dec 31, 2009
2,148,826
1,639,385
3,217,458
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
MRVB
MRVB
MRVB
MRVB
MRVB
MRVB
1
2010
3,910
5,401
15,925
2,647,460
1,747,158
3,291,197
2
2010
3,491
4,647
13,782
2,650,951
1,751,805
3,304,979
3
2010
3,823
5,084
14,705
2,654,775
1,756,889
3,319,684
4
2010
3,661
5,231
15,002
2,658,436
1,762,120
3,334,687
5
2010
3,485
4,994
14,851
2,661,920
1,767,114
3,349,538
6
2010
3,536
4,522
14,979
2,665,456
1,771,636
3,364,516
7
2010
3,548
4,584
15,064
2,669,005
1,776,220
3,379,580
8
2010
3,594
4,623
14,931
2,672,599
1,780,843
3,394,511
9
2010
3,570
4,805
14,555
2,676,169
1,785,649
3,409,066
10
2010
3,778
5,329
15,496
2,679,947
1,790,978
3,424,562
11
2010
3,265
5,146
14,040
2,683,212
1,796,124
3,438,603
12
2010
3,471
5,202
14,733
2,686,683 ..
1,801,326'
3,453,336
2010 TOTAL
43,132
59,568
178,064
Cumulatives
at Dec 31, 2009
2,643,550
1,741,758
3,275,271
ATTACHMENT 3
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Injected Fluid Volumes
Injected Fluid Volumes (Reservoir Units)
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
MSTB
MMSCF
MMSCF
MSTB
MMSCF
MMSCF
1
2010
18,937
1,477
4,314
5,478,261
1,126,420
1,067,134
2
2010
16,789
1,777
3,410
5,495,050
1,128,197
1,070,544
3
2010
18,453
2,468
3,034
5,513,503
1,130,665
1,073,579
4
2010
18,468
3,040
2,194
5,531,971
1,133,706
1,075,773
5
2010
16,948
1,122
4,000
5,548,918
1,134,828
1,079,773
6
2010
16,210
946
3,957
5,565,128
1,135,774
1,083,730
7
2010
16,154
2,897
2,523
5,581,282
1,138,671
1,086,253
8
2010
16,053
4,286
780
5,597,336
1,142,957
1,087,033
9
2010
16,723
1,218
4,378
5,614,059
1,144,176
1,091,410
10
2010
17,267
1,327
5,136
5,631,326
1,145,503
1,096,546
11
2010
15,263
1,393
4,878
5,646,589
1,146,896
1,101,424
12
2010
17,740
1,067
5,348
5 664,329'
1 147�963� 106;772
2010 TOTAL
205,005
23,020
43,953
2010 TOTAL
209,105
Cumulatives at
Dec 31, 2009
5,459,324
1,124,943
1,062,819
Injected Fluid Volumes (Reservoir Units)
WATER
GAS
Mi
CUM WATER
CUM GAS
CUM MI
MO
YR
MRVB
MRVB
MRVB
MRVB
MRVB
MRVB
1
2010
19,315
1,313
3,266
5,575,602
989,859
801,594
2
2010
17,125
1,580
2,582
5,592,727
991,439
804,175
3
2010
18,822
2,194
2,297
5,611,549
993,633
806,473
4
2010
18,837
2,703
1,661
5,630,386
996,336
808,133
5
2010
17,287
997
3,028
5,647,673
997,334
811,162
6
2010
16,534
841
2,996
5,664,207
998,175
814,157
7
2010
16,477
2,575
1,910
5,680,684
1,000,751
816,067
8
2010
16,374
3,810
590
5,697,059
1,004,561
816,657
9
2010
17,058
1,083
3,314
5,714,116
1,005,644
819,971
10
2010
17,612
1,180
3,888
5,731,728
1,006,824
823,859
11
2010
15,569
1,239
3,692
5,747,297
1,008,063
827,551
12
2010
18,095
948
4,049
5,765,392 009;011
$31,600 _
2010 TOTAL
209,105
20,465
33,272
Cumulatives at Dec 31, 2009
5,556,287
988,546
798,328
ATTACHMENT 4
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Reservoir Pressure Surveys
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Kuparuk River Oil Pool — Proposed Pressure Survey Plan for 2011
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 8, Conservation Order No. 432, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Oil Pool, is hereby submitting the proposed pressure survey plan for 2011.
There were 236 pressure surveys reported for the Kuparuk River Oil Pool to the AOGCC in 2010.
In 2011, we expect to conduct approximately 150 pressure surveys, including initial surveys for new wells
prior to initial sustained production.
If you have any questions concerning this data, please contact Mark Kovar at 265-6097.
Sincerely,
7
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
Re: Kuparuk River Oil Pool — Proposed Injection Profile Survey Plan for 2011
Dear Commissioner Seamount,
In compliance with Rule 4, Conservation Order No. 1988, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Oil Pool, is hereby submitting the proposed injection profile survey plan for 2011.
There were 34 injection surveys reported for the Kuparuk River Oil Pool to the AOGCC in 2010.
In 2011, we expect to conduct approximately 40 injection surveys, including initial surveys for new wells
prior to initial sustained injection.
If you have any questions concerning this data, please contact Mark Kovar at 265-6097.
Sincerely,
`James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ATTACHMENT 7
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Miscible Injectant Composition
Miscible Injectant (MI) is manufactured at CPF-1 and CPF-2. The compositions of both the lean
gas, enriching fluids (NGLs) and the resulting MI are measured periodically throughout the year
to ensure that the MI meets the design Minimum Miscible Pressure (MMP). The detailed
compositional analysis of the MI from each CPF is provided in tabular form on the following
pages, together with the Minimum Miscible Pressures (MMP). The target MMP is 3300 psia. A
lower MMP means higher NGL content in MI.
Cd
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l(O
ATTACHMENT 8
Kuparuk River Unit
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
LSEOR Development Plan
During 2010, the Greater Kuparuk Area (GKA) averaged 17,489 BPD of PBU NGL imports and
6,303 BPD of indigenous NGLs for an annual average of 167 MMSCFD of Miscible Injectant (MI)
manufacture. Of the total MI production in 2010, 119 MMSCFD was injected into the Kuparuk
Field, 2.5 MMSCFD used as lift gas in Drillsite 3S and the rest was used in satellite fields. Within
the main Kuparuk Field, 2 MMSCFD was injected into the SSEOR and SSEORX drillsites, 42
MMSCFD into the LSEOR drillsites and 75 MMSCFD into the LSEOR expansion drillsites.
LSEOR expansion drillsites include drillsites: 1 B, 1 C, 1 D, 1 E, 1 L, 3B, 3G, 31-1, 30, 3Q and 3S.
Further drilling activity in the Kuparuk River Oil Pool potentially provides new opportunities to
maximize field recovery while preventing physical waste. Drilling opportunities, along with their
associated miscible gas EOR potential, are under constant evaluation as the field matures,
geologic and reservoir performance information is assimilated and as technology improves.
Although drillsite 1 D is the only recent drillsite-level expansion project being sanctioned, the
Kuparuk EOR project may be expanded to include any new wells.
MWAG expansion to drillsite 1 D was completed during 2008, as part of the LSEOR expansions.
Very positive responses from the MI injection have been observed during 2010.
N
3
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ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Greater Kuparuk Area 2010 Shut-in Well Report
Kuparuk, Meltwater, Tarn, Tabasco, and West Salk Oil Pools
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with AOGCC regulation 20 AAC 25.115(a), ConocoPhillips Alaska, Inc., as operator of the
subject oil pools in the Greater Kuparuk Area, is hereby submitting the 2010 Shut-in Well Report for wells
shut-in 365 days or longer during 2010.
The attached document lists all wells in the Greater Kuparuk Area that were shut-in for 365 days or more
during 2010. It also lists the reason the wells were shut-in, as well as the mechanical condition of the well
and any future plans for the well.
If you have any questions concerning this data, please contact Mark Kovar at 265-6097.
Sincerely,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 Meltwater Oil Pool Annual Reservoir Surveillance Report
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 10, Conservation Order No. 456, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Field, is hereby submitting the annual surveillance report on the Meltwater Oil Pool. This
report documents the required information pertinent to the field development and enhanced recovery
operations from January through December 2010. The following is an outline of the information provided:
a. Progress of EOR project and reservoir management summary (Attachment 1).
b. Voidage balance, by month, for produced and injected fluids (Attachments 2 and 3).
c. Analysis of reservoir pressure surveys taken in 2010 (Attachment 4).
d. Results of production surveys, and any special surveys, taken on the Meltwater Oil Pool in 201
(Attachment 5).
e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring
(Attachment 6).
f. Development Plan and Operation Review (Attachments 7 and 8).
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
I
ames T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ATTACHMENT 1
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Summary of EOR Project and Reservoir Management Summary
Background
In 2001, CPAI received approvals for formation of the Meltwater Oil Pool in the Kuparuk River
Unit, an Area Injection Order for Meltwater, expansion of the Kuparuk River Unit, and formation of
• the Meltwater Participating Area. The Meltwater Pool Rules and Area Injection Order were
approved on August 1, 2001. The Unit Expansion and Participating area were approved effective
June 1, 2001.
Injection of miscible injectant (MI) began in January 2002 and the MWAG (miscible water
• alternating gas) process was implemented during May 2003. The Meltwater MWAG process uses
Kuparuk spec MI which is injected above the minimum miscibility pressure. For compositional
analysis of the Kuparuk spec Ml, refer to the Kuparuk section of the annual surveillance report.
The Meltwater field currently has 19 total wells (13 producers and 6 injectors). See Attachment 8
for well locations.
Progress of EOR Project
Development activities in 2010 followed the plans described in the Pool Rules, Area Injection
Order, Unit Expansion, and Participating Area (PA) applications. Below is a listing of the key
events related to the Meltwater Pool and PA in 2010:
1. Water injection ceased in the Meltwater Field on October 15, 2009. On this date the
water injection line to the Meltwater field was declared unsuitable for continued operation
due to internal corrosion. Miscible gas injection (MI) continues to maintain voidage
replacement for production in the field. At this time there are no near-term plans to
restore water injection service to Meltwater. ConocoPhillips does not anticipate any
recovery impacts as little pressure support has been observed to date from water
injection. Studies are ongoing to determine the future development options for the highly
compartmentalized Meltwater reservoir in light of the de -rated water injection pipeline.
2. Due to the high reservoir pressure and lack of clear interactions with offset producers well
2P-434 was shut in August 2007. In June 2008, two additional injection wells, 2P-419 and
2P-432, were shut in. In order to facilitate pressure reductions that would allow wells to
be safely sidetracked in this area of the reservoir, it was decided to flowback these
injectors through the surface header facilities of long term shut-in producers. Well 2P-
432, wth a bottom hole pressure of 4366 psi began flowback in February 2009. Plant
constraints will dictate when the other injectors can commence flowbacks. Shut-in
bottomhole pressure for this well was >3021 psi as of September 2010. The initial
flowrate for well 2P-432 was 3,000 BWPD with very small amounts of oil and gas. As of
December 31, 2010, the water cut has stabilized at --90%, the gas -oil ratio is 15000
SCF/BBL, with the total liquid rate of 1,600 BBL/D.
3. A total of eight wells including six producers are currently shut-in. Wells 2P-441, 2P -448A
and 2P-451 are shut-in due to insufficient pressure support (reservoir
compartmentalization). Well 2P-438 suffered early water breakthrough in 2007 and has
been shut in since. Wells 2P-406, 2P-415, 2P -424A, and 2P-443 were lifted via surface -
powered jet pumps (SPJP) that utilized injection water as power fluid. These wells were
shut in on October 15, 2009 when the water injection line to Meltwater was taken out of
service (See point 1). Wells 2P-406, 2P -424A, and 2P-443 have been converted to gas
lift service to restore production. Well 2P-415 was tested at less than 10 BOPD before it
had to be shut in. This well cannot be produced economically. Well 2P-443 has a history
0
of severe paraffin deposition and freezing problems and it will be an intermittent producer
for the foreseeable futue.
4. While most producer/injector patterns see fairly limited communication, producer 2P -
424A saw a relatively strong response beginning December 2008. This production
response is suspected to be a result of offset gas injection into 2P-427 which
commenced in June 2008. This improved performance has been observed all throughout
2009 and continues in 2010. Early 2009, well 2P-417 started responding in a similar way
to MI injection into well 2P-420 that commenced in June 2008. Well 2P -417's incremental
oil rate associated to this event peaked at approximately 1,000 bopd in December 2009
and has been declining steadily since.
Significant Studies in Progress
Work is ongoing to rebuild the Meltwater subsurface model. Much of the work involves
analyzing the new seismic data obtained during winter 2007-2008. The analysis of this
4D seismic data should provide a better interpretation of the reservoir architecture and
communication between producers and injectors. Preliminary studies of certain 4D
effects, such as changes in amplitudes and velocities, show clear trends of anomalies in
the form of lineaments that match the location of active injectors and trend in a NNW -
SSE direction.
This direction coincides with the direction of preferential flow from injectors to producers
that has been identified at the Tarn and Meltwater fields by means of production
surveillance and well interaction analyses. Fluids injected into the reservoir above parting
pressure (required to achieve adequate injectivity) probably propagate quickly along the
plane perpendicular to the minimum stress opening fractures or traveling in a pre-existing
fracture system. Producers aligned on this trend with injectors are susceptible to early
water breakthrough and multiple injectors aligned on this axis may link up forming a
single injection line.
As mentioned earlier in this document, a flowback from the injection well 2P-432 was
started in February 2009 in an attempt to decrease reservoir pressures to levels at which
sidetracks can be drilled. Well 2P-432 initially flowed at approximately 3,000 bbl/day with
100% water showing only traces of oil and gas. Pressure surveys early in the year
indicated no change in reservoir pressure. When injection water supply to Meltwater
ceased on October 15, 2009, the injection well 2P-429 that was still injecting water at that
time was shut in. After an initial spike in oil production, watercut stabilized at --90% while
gas -oil ratio increased. The last pressure survey (September 4, 2010) showed that the
pressure decreased approximately 1200 psi after injection in well 2P-429 ceased. Unless
detrimental effects are observed on neighboring producers, production from 2P-432 will
continue as it increases fluid velocity and temperature in the oil production line. Higher
fluid velocities minimize corrosion in this valuable pipeline and higher temperatures will
reduce backpressure at the drillsite thereby minimizing production impacts.
2. Outer annuli pressures in 2P-406, 2P-431, 2P-432, 2P-438, 2P-447, 2P -448A, and 2P-
451 remained at elevated levels in 2010. Fluid levels continue to be shot monthly for all
problem wells and the calculated pressures at the C-80 interval are still below the
measured/calculated leak off (refer to table of elevated OA pressures in Meltwater -
Attachment 6).
Reservoir Management Summary
Meltwater came on-line in November of 2001 and has cumulatively produced 15.1 MMBO, 3.0
MMBW, and 35.6 BCF of gas by year-end 2010. Miscible gas injection began in 2002 with water
injection beginning in 2003 (MWAG cycles). Cumulative injection through year-end 2010 at
Meltwater has been 25.1 MMBW and 48.9 BCF of gas (43.1 BCF of MI gas and 5.8 BCF of lean
gas). Water injection ceased on October 15, 2009 when the water injection line had to be taken
out of service due to operational constraints caused by areas of excessive under -deposit
corrosion pitting.
When phase II injection wells were drilled in 2004, cumulative injection/withdrawal (INV) for the
field was approximately 0.75. INV rates for subsequent years were approximately 1.5 to restore
adequate voidage replacement. In late 2004, cumulative INV reached 1.0 and has climbed to the
current value of 1.3. Despite three injectors being taken off-line in 2008, instantaneous I/W has
remained above 2.0 for much of 2008. The cumulative year-end 2008 INV ratio increased to 1.3.
While it would have been advantageous to continue decreasing injection at that time, a minimum
amount of both gas and water had to be transported to Meltwater to maintain line velocities in
order to minimize corrosion in the water line and freezing in the gas line. Despite these efforts,
the water injection line to Meltwater had to be taken out of service on October 15, 2009 based on
results obtained from a "smart pig" run and additional follow-up surveys completed during 2009.
Currently, the plan is to balance voidage with gas injection until the studies to evaluate
development alternatives for Meltwater are completed and implemented. (Refer to letters to
AOGCC dated December 21, 2009 and December 15, 2010). The cumulative year-end 2010 INV
ratio is 1.3.
Attachment 2
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Produced Fluid Volumes
Cumulatives at Dec 31, 2009 14092379 32004582 2066292
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
STB
MSCF
STB
STB
MSCF
STB
1
2010
95485
134255
123608
14187864
32138837
2189900
2
2010
79319
174127
79249
14267183
32312964
2269149
3
2010
98468
252344
130720
14365651
32565308
2399869
4
2010
94466
314244
97748
14460117
32879552
2497617
5
2010
88909
288425
82628
14549026
33167977
2580245
6
2010
103170
297455
72951
14652196
33465432
2653196
7
2010
92174
341675
72167
14744370
33807107
2725363
8
2010
79436
334739
31277
14823806
34141846
2756640
9
2010
70582
357046
36824
14894388
34498892
2793464
10
2010
72933
377242
65612
14967321
34876134
2859076
11
2010
64678
311069
56232
15031999
35187203
2915308
12
2010
67040
375541
51330
15099039'
35562744
�: 2966638„
2010
TOTAL
1006660
3558162
900346
Cumulatives at Dec 31, 2009 14092379 32004582 2066292
Produced Fluid Volumes (Reservoir Units)
Cumulatives at Dec 31, 2009 18772013 21705422 2089477
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
127472
56961
125339
18899485
21762383
2214816
2
2010
105891
94707
80358
19005376
21857089
2295174
3
2010
131455
144959
132550
19136831
22002048
2427724
4
2010
126112
193689
99116
19262943
22195737
2526841
5
2010
118694
176744
83785
19381637
22372481
2610625
6
2010
137732
176908
73972
19519369
22549389
2684598
7
2010
123052
215527
73177
19642421
22764915
2757775
8
2010
106047
216235
31715
19748468
22981150
2789490
9
2010
94227
237264
37340
19842695
23218414
2826829
10
2010
97366
251452
66531
19940061
23469866
2893360
11
2010
86345
205221
57019
20026406
23675087
2950379
12
2010
89498
252921
52049
15964'
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2010 TOTAL
1343891
2222587
912951
Cumulatives at Dec 31, 2009 18772013 21705422 2089477
Attachment 3
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Injected Fluid Volumes
Cumulatives at Dec 31, 2009 25488360 4582498 33947156
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
STB
MSCF
MSCF
STB
MSCF
MSCF
1
2010
0
0
484848
25136450
3821922
39884409
2
2010
0
26959
351959
25136450
3848881
40236368
3
2010
0
76566
335686
25136450
3925447
40572054
4
2010
0
267159
156042
25136450
4192606
40728096
5
2010
0
30127
450697
25136450
4222733
41178793
6
2010
0
27144
507303
25136450
4249877
41686096
7
2010
0
225015
258914
25136450
4474892
41945010
8
2010
0
397316
78376
25136450
4872208
42023386
9
2010
0
0
515043
25136450
4872208
42538429
10
2010
0
0
508529
25136450
4872208
43046958
11
2010
0
0
434449
25136450
4872208
43481407
12
2010
0
0
377948
25136450
4872208
43859355
2010 TOTAL
0
1050286
4459794
Cumulatives at
Dec 31, 2009
25136450
3821922
39399561
Injected Fluid
Volumes (Reservoir Units)
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
0
0
367030
25488360
4582498
34314186
2
2010
0
29898
266433
25488360
4612396
34580619
3
2010
0
84912
254114
25488360
4697307
34834733
4
2010
0
296279
118124
25488360
4993587
34952857
5
2010
0
33411
341178
25488360
5026997
35294035
6
2010
0
30103
384028
25488360
5057100
35678063
7
2010
0
249542
195998
25488360
5306642
35874061
8
2010
0
440623
59331
25488360
5747265
35933392
9
2010
0
0
389888
25488360
5747265
36323279
10
2010
0
0
384956
25488360
5747265
36708236
11
2010
0
0
328878
25488360
5747265
37037113
12
2010
0
0
286107
25488360
5747265
v87323220'
2010 TOTAL
0
1164767
3376064
Cumulatives at Dec 31, 2009 25488360 4582498 33947156
ATTACHMENT 4
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Reservoir Pressure Surveys
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Meltwater Oil Pool — Proposed Pressure Survey Plan for 2011
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
Dear Commissioner Seamount,
In compliance with Rule 7, Conservation Order No. 456A, ConocoPhillips Alaska, Inc., operator of the
Meltwater Oil Pool, is hereby submitting the proposed pressure survey plan for 2011.
There were 8 pressure surveys reported for the Meltwater Oil Pool to the AOGCC in 2010.
In 2011, we expect to conduct approximately 7 pressure surveys, including regularly scheduled surveys to
assess the progress of the injector flowback currently underway.
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely, /
mes T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ATTACHMENT 5
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Production & Special Surveys
During 2010, no production/injection profile logs or special surveillance logs were run. A 2-4 week flowing
bottomhole pressure survey (FBHP) will be conducted on one well in 2011 to better understand
production well behavior.
ATTACHMENT 6
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Results of Well Allocation, Test Evaluation, and Special Monitoring
Well Allocation
Meltwater drillsite 2P facilities were fabricated with a conventional test separator. A minimum of two well
tests per month were taken on production wells. Test separator backpressure corrections were applied to
wells that experienced greater than 100 psi backpressure over header pressure. Correction to stock tank
barrel conditions were made by applying Meltwater specific pressure corrections (derived from the PVT
analysis of Meltwater North #1 crude oil samples) and API temperature corrections.
Miscible gas is used for injection and gas lift at drillsite 2P. For the wells that were on MI lift during a well
test, the metered liquid rates were adjusted for NGLs associated with MI lift. Production volumes were
tracked through an automated production monitoring SCADA system (SetCIM). The 2010 Meltwater
allocation factors by month are listed below.
Month
Oil
Gas
Water
Jan -10
0.990516
0.828032
1.059452
Feb -10
0.978607
0.815357
1.029321
Mar -10
0.978387
0.820839
1.015742
Apr -10
0.988700
0.905700
1.067567
May -10
0.988258
0.899935
1.087839
Jun -10
0.998633
0.887900
1.096567
Jul -10
0.976000
0.921742
1.102065
Aug -10
0.980194
0.898806
1.079484
Sep -10
0.993133
0.876100
1.037400
Oct -10
0.986516
0.895710
1.067355
Nov -10
1.008000
0.915000
1.086367
Dec -10
0.991710
0.901645
1.089452
Shallow Gas Special Monitoring
Wells 2P-406, 2P-431, 2P-432, 2P-434, 2P-438, 2P-441, 2P-447, 2P -448A and 2P-451 have a history of
elevated outer annulus (OA) pressures that may rebuild pressure after bleeding. The surface pressures
are monitored daily via SetCIM (wells have pressure transducers that transmit real-time OA pressures).
Fluid levels are surveyed approximately once per month via echometer measurements. Calculations are
then made to determine the approximate pressures in the outer annulus at the C-80 interval in each of the
wells that have elevated surface OA pressures. This data is then sent to the AOGCC on a quarterly basis.
(See table on following page).
Throughout 2010 most wells exhibited relatively stable OA pressures with the exception of 2P-434 and
2P-438 which continued to experience gradual decreasing OA pressures. While there appears to be a
connection between the cessation of injection in these wells and declining OA pressures, OAP and
injection rates do not match up in time. Therefore, there is inconclusive evidence to say there is a
relationship between the two.
The OA pressure of well 2P-434 has declined to less than 150 psig at surface since cessation of injection
into this well in August 2007.
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ATTACHMENT 7
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Meltwater Development Plan and Operational Review
Following are summaries of key activities that are planned for 2011 and subsequent years.
Development Drilling
Development opportunities are being analyzed in light of the new seismic data, recent surveillance
findings and the absence of injection water supply.
Digital processing of the 2007-2008 winter seismic survey is complete and the data is being analyzed.
This data will help in evaluating the potential of the peripheral edges of the Meltwater pool, analyzing
producer -injector patterns, and identifying infill drilling potential. Well 2P-432 began flowback operations
in February 2009 to decrease the elevated reservoir pressures in this portion of the reservoir. This
flowback will continue because it provides a substantial portion of the fluid velocity and temperature in the
oil production pipeline from the Meltwater field. This will make potential Coiled Tubing Drilling sidetrack
operations safer. Further flowbacks will be started based on results from 2P-432 and operational
constraints (processing facility impacts).
Pipeline Operations
Due to low flow rates through the water injection line, there has been awareness of increased risk for
microbial -induced under -deposit corrosion and increased diagnostic work was being conducted. Frequent
pigging of the production and water injection lines was conducted to minimize effects of under -deposit
corrosion. Despite these efforts, the water injection line had to be taken out of service on October 15,
2009, due to operational constraints caused by areas of excessive under -deposit corrosion pitting.
Exploration/Delineation
No further exploration work is currently planned for the Bermuda interval. However, the overlying Cairn
sand, believed to be gas bearing, had been targeted for 2009 development in order to supply fuel gas to
the Kuparuk facilities. Pre -drill engineering assessments determined that probable volumes accessible
from the 2P pad were insufficient for economic development at this time.
ATTACHMENT
Meltwater Oil Pool
2010 Annual Reservoir Surveillance Report
Map showing Development as of December 31, 2010
Disposal Well
z IWAG
MWAG
t
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SW PW i�Y l l 01 Producer
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Suspended
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2R415
1 y
Cr
0)
N
A
O
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 Tabasco Oil Pool Annual Reservoir Surveillance Report
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 11, Conservation Order No. 435, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Field, is hereby submitting the annual surveillance report on the Tabasco Oil Pool. This
report documents the required information pertinent to the field development and enhanced recovery
operations from January through December 2010. The following is an outline of the information provided:
a. A summary of the enhanced recovery project (Attachment 1).
b. Voidage balance, by month, for produced and injected fluids (Attachments 2 and 3).
c. Analysis of reservoir pressure surveys taken in 2010 (Attachment 4).
d. Results of production surveys, and any special surveys, taken on the Tabasco Oil Pool in 2010
(Attachment 5).
e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring
(Attachment 6).
f. Future development plans (Attachment 7).
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
r]jmes T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ATTACHMENT 1
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Summary of the Enhanced Recovery Project
Tabasco produced 755 MBO of crude, 100 MMSCF of gas, and 5062 MBW during 2010. Water injection
was 5370 MBW over the same period. Cumulative oil, gas, water production, and water injection through
year-end 2010 were 16.3 MMBO, 2.7 BCF, 65.3 MMBW, and 75.8 MMBWI, respectively. The cumulative
year-end 2010 INV ratio, based on current formation volume factors, is estimated at 0.91 for Tabasco.
Year-end 2010 Tabasco well count (all at Kuparuk River Unit Drill Site 2T) was:
Producers: 9 completed 6 on-line
Injectors: 3 completed 1 on-line
The water oil ratio (WOR) was 7.48 at the end of 2010 compared to 6.92 at the end of 2009. Water
breakthrough has occurred at all producers. Production and injection logs, coupled with the structural
positions and water breakthrough histories of the producers, suggest that the water production
mechanism is dominated by gravity -induced slumping.
Attempts were made in April 2010 to diagnose the tubing patch leak in well 2T-220. During diagnostic
operations the well quit surfacing fluids due to electric submersible pump (ESP) failure. The well
remained shut-in throughout 2010 and is scheduled for a rig workover (RWO) in September 2011 to
replace the tubing string and ESP assembly.
The full field model for Tabasco will continue to be worked in 2011 so that it can be used to optimize
waterflood strategy and explore development options.
Attachment 2
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Produced Fluid Volumes
Cumulatives at Dec 31, 2009 15602983 2591130 60529679
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
STB
MSCF
STB
STB
MSCF
STB
1
2010
68376
8248
427122
15671359
2599378
60956801
2
2010
59008
6969
371463
15730367
2606347
61328264
3
2010
69705
8292
406948
15800072
2614639
61735212
4
2010
58377
7947
398629
15858449
2622586
62133841
5
2010
63694
8555
449686
15922143
2631141
62583527
6
2010
68006
8846
440406
15990149
2639987
63023933
7
2010
65503
9034
413036
16055652
2649021
63436969
8
2010
63879
8887
433396
16119531
2657908
63870365
9
2010
61869
8224
407113
16181400
2666132
64277478
10
2010
61655
8610
429783
16243055
2674742
64707261
11
2010
55811
8320
439135
16298866
2683062
65146396
12
2010
59550
8319
445646
16358416"-"
2691081�'°.°65592042
65592042
2010
TOTAL
755433
100251
5062363
Cumulatives at Dec 31, 2009 15602983 2591130 60529679
Produced Fluid Volumes (Reservoir Units)
2010 TOTAL 800759 51 5062363
Cumulatives at Dec 31, 2009 16512919 76165 60529679
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
72479
0
427122
16585398
76165
60956801
2
2010
62548
0
371463
16647946
76165
61328264
3
2010
73887
0
406948
16721833
76165
61735212
4
2010
61880
0
398629
16783713
76165
62133841
5
2010
67516
0
449686
16851229
76165
62583527
6
2010
72086
0
440406
16923315
76165
63023933
7
2010
69433
0
413036
16992748
76165
63436969
8
2010
67712
0
433396
17060460
76165
63870365
9
2010
65581
0
407113
17126041
76165
64277478
10
2010
65354
0
429783
17191395
76165
64707261
11
2010
59160
51
439135
17250555
76216
65146396
12
2010
63123
0
445646
;17313678
76216
65592042
2010 TOTAL 800759 51 5062363
Cumulatives at Dec 31, 2009 16512919 76165 60529679
Attachment 3
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Injected Fluid Volumes
Cumulatives at Dec 31, 2009 70497233 0 0
Injected Fluid Volumes (Reservoir Units)
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
STB
MSCF
MSCF
STB
MSCF
MSCF
1
2010
443623
0
0
70940856
0
0
2
2010
407467
0
0
71348323
0
0
3
2010
474917
0
0
71823240
0
0
4
2010
449135
0
0
72272375
0
0
5
2010
439289
0
0
72711664
0
0
6
2010
445755
0
0
73157419
0
0
7
2010
447379
0
0
73604798
0
0
8
2010
472372
0
0
74077170
0
0
9
2010
447842
0
0
74525012
0
0
10
2010
458888
0
0
74983900
0
0
11
2010
431661
0
0
75415561
0
0
12
2010
451491
0
0
758670520.
0` .
2010
TOTAL
5369819
0
0
Cumulatives at Dec 31, 2009 70497233 0 0
Injected Fluid Volumes (Reservoir Units)
Cumulatives at Dec 31, 2009 70497233 0 0
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
443623
0
0
70940856
0
0
2
2010
407467
0
0
71348323
0
0
3
2010
474917
0
0
71823240
0
0
4
2010
449135
0
0
72272375
0
0
5
2010
439289
0
0
72711664
0
0
6
2010
445755
0
0
73157419
0
0
7
2010
447379
0
0
73604798
0
0
8
2010
472372
0
0
74077170
0
0
9
2010
447842
0
0
74525012
0
0
10
2010
458888
0
0
74983900
0
0
11
2010
431661
0
0
75415561
0
0
12
2010
451491
0
0
2010
TOTAL
5369819
0
0
Cumulatives at Dec 31, 2009 70497233 0 0
ATTACHMENT 4
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Reservoir Pressure Surveys
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Tabasco Oil Pool — Proposed Pressure Survey Plan for 2011
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 8, Conservation Order No. 435A, ConocoPhillips Alaska, Inc., operator of the
Tabasco Oil Pool, is hereby submitting the proposed pressure survey plan for 2011.
One pressure survey was completed within the Tabasco Oil Pool in 2010.
No formal pressure surveys are scheduled for 2011, though surveys may be conducted using ESP
pressure gauges should any well be shut in for an extended period.
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
t
es T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ATTACHMENT 5
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Production Logs and Special Surveys
No logs or surveys were run in 2010.
Since production wells are completed with gravel pack screens and electrical submersible pumps, no
production logs or special surveys are planned for 2011.
ATTACHMENT 6
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Results of Well Allocation
A minimum of two well tests per month were conducted on production wells. Fluid samples were obtained
on a regular basis, and water cut corrections were applied to well tests as required based on subsequent
lab analysis. Generally, good agreement was observed for water cuts comparing phase dynamics and
shakeout analysis. Production volumes were tracked through the Setcim production monitoring SCADA
system. In 2002, Tabasco switched from an allocation factor of 1.0 to floating production allocation
factors. Tabasco 2010 production allocation factors were as follows:
Month
Oil
Gas
Water
Jan -10
0.990
0.828
1.059
Feb -10
0.979
0.815
1.029
Mar -10
0.978
0.821
1.016
Apr -10
0.922
0.845
0.996
May -10
0.988
0.899
1.088
Jun -10
0.999
0.888
1.097
Jul -10
0.976
0.922
1.102
Aug -10
0.980
0.899
1.079
Sep -10
0.993
0.876
1.037
Oct -10
0.987
0.896
1.067
Nov -10
1.008
0.915
1.086
Dec -10
0.992
0.902
1.089
ATTACHMENT 7
Tabasco Oil Pool
2010 Annual Reservoir Surveillance Report
Future Development Plans
Tabasco injection withdrawal ratios (INV ratio) will be monitored to maintain an instantaneous value of 1.0
or greater. Adjustments to injection and/or production rates will be made to maintain an instantaneous I/W
ratio of 1.0 or greater so that gas will remain in solution and pressure support maintained for the Tabasco
reservoir.
There are 2 rig workovers scheduled during 2011 for Tabasco vertical producers 2T-220 and 2T-202. The
rig workovers will consist of pulling and replacing the current ESP completion.
Once 2T-220 producer is returned to service, the 2T-217 injector will also be returned to service to help
provide better sweep efficiency. Well 2T-217 has remained shut in throughout 2010 in an attempt to
prohibit possible flow to surface in offset shut in producer well 2T-220. Injection rate in well 2T-201 will be
decreased as well 2T-217 comes online to help keep a target IW of 1
The full field model for Tabasco will continue to be worked in 2011 so that it can be used to optimize
waterflood strategy and explore development options
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 Tarn Oil Pool Annual Reservoir Surveillance Report
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 11, Conservation Order No. 430, ConocoPhillips Alaska, operator of the Kuparuk
River Field, is hereby submitting the annual surveillance report on the Tarn Oil Pool. This report
documents the required information pertinent to the field development and enhanced recovery operations
from January through December 2010. The following is an outline of the information provided:
a. A summary of the enhanced recovery project (Attachment 1).
b. Woidage balance, by month, for produced and injected fluids (Attachments 2 and 3).
c. Analysis of reservoir pressure surveys taken in 2010 (Attachment 4).
d. Results of production surveys, and any special surveys, taken on the Tarn Oil Pool in 2010
(Attachment 5).
e. Results of well allocation and test evaluation for Rule 7, and any other special monitoring
(Attachment 6).
f. Development Plan and Operational Review (Attachments 7 and 8).
If you have any questions concerning this data, please contact Mark Kovar (907) 265-6097.
Sincerely,
lla es T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ATTACHMENT 1
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Summary of EOR Project and Reservoir Management Summary
Background
In 1998 Arco Alaska, Inc. received approvals for formation of the Tarn Oil Pool in the Kuparuk River Unit,
an Area Injection Order for Tarn, expansion of the Kuparuk River Unit, and formation of the Tarn
Participating Area. The Tarn Pool Rules and Area Injection Order were approved on July 21St and July
20th, 1998 respectively. The Unit Expansion and Participating area were approved effective July 1, 1998.
Construction of the Tarn road, pads, powerlines, and pipelines took place in the 1998/1999 winter
construction season. Tarn development drilling commenced in April of 1998. Tarn production began on
July 8, 1998. Injection of miscible injectant (MI) began in November 1998. Tarn switched to a miscible
water alternating gas (MWAG) recovery process in July 2001.
Progress of EOR Project
The permanent 12" water injection line was completed and brought on-line in July 2001. This allowed
Tarn to switch from strictly an MI flood to an MWAG recovery process which increases ultimate recovery
from the Tarn reservoir. Water injection capacity has been good and injectivity has remained strong with
no signs of formation damage. Tarn is operating at injection pressures above parting pressure which
enables water injection to match offtake.
The Tarn MWAG process uses Kuparuk spec MI which is injected above the minimum miscibility
pressure. For compositional analysis of the Kuparuk spec MI, refer to the Kuparuk section of the annual
surveillance report.
Reservoir Management Summary
In 2010, Tarn produced 4.25 MMBO, 6.37 MMBW, and 7.49 BSCF gas. The injection totals for 2010 were
0.89 BSCF Lean Gas, 5.00 BSCF of MI and 15.54 MMBW. The 2010 INV ratio is 1.18 for Drill Site 2N,
and 1.19 for Drill Site 2L. Plans are to continue maintaining reservoir pressure by balancing monthly
injection and production rates.
ATTACHMENT 2
Tarn River Oil Pool
2010 Annual Reservoir Surveillance Report
Produced Fluid Volumes
2010 TOTAL 4251000 7488063 6370087
Cumulatives at Dec 31, 2009 96631001 15200226 43896648
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
STB
MSCF
STB
STB
MSCF
STB
1
2010
384619
713379
733800
97015620
15913605
44630448
2
2010
355610
649417
565093
97371230
16563022
45195541
3
2010
349934
638044
610962
97721164
17201066
45806503
4
2010
324606
697091
627556
98045770
17898157
46434059
5
2010
318575
634990
680927
98364345
18533147
47114986
6
2010
377328
729615
628919
98741673
19262762
47743905
7
2010
392473
770979
514921
99134146
20033741
48258826
8
2010
360772
658783
395662
99494918
20692524
48654488
9
2010
360578
546725
387089
99855496
21239249
49041577
10
2010
369438
534162
420849
100224934
21773411
49462426
11
2010
340440
495916
399245
100565374
22269327
49861671
12
2010
316627
418962
405064
100882001''
22688289
50266735x+;
2010 TOTAL 4251000 7488063 6370087
Cumulatives at Dec 31, 2009 96631001 15200226 43896648
Produced Fluid Volumes (Reservoir Units)
Cumulatives at Dec 31, 2009 129654053 134470203 44511201
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
518347
534610
744073
130172400
135004813
45255274
2
2010
479898
479806
573004
130652299
135484619
45828279
3
2010
472385
470089
619515
131124683
135954708
46447794
4
2010
437908
556010
636342
131562592
136510718
47084136
5
2010
429749
493624
690460
131992341
137004342
47774596
6
2010
509724
557967
637724
132502064
137562309
48412320
7
2010
530951
587042
522130
133033015
138149352
48934449
8
2010
487908
481527
401201
133520923
138630879
49335651
9
2010
487397
358387
392508
134008320
138989265
49728159
10
2010
499171
338230
426741
134507491
139327495
50154900
11
2010
459988
314147
404834
134967479
139641642
50559734
12
2010
427285
246049
410735
135394764'
13988769(
60970469."'
2010
TOTAL
5740711
5417488
6459268
Cumulatives at Dec 31, 2009 129654053 134470203 44511201
ATTACHMENT 3
Tarn River Oil Pool
2010 Annual Reservoir Surveillance Report
Injected Fluid Volumes
Cumulatives at Dec 31, 2009 136041225 13262716 169139456
Injected Fluid Volumes (Reservoir Units)
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
STB
MSCF
MSCF
STB
MSCF
MSCF
1
2010
1629347
0
502802
137670572
13262716
169642258
2
2010
1520137
29667
224172
139190709
13292383
169866430
3
2010
1435909
74168
604394
140626618
13366551
170470824
4
2010
878881
441671
560934
141505499
13808222
171031758
5
2010
1046616
63611
943903
142552115
13871833
171975661
6
2010
1193557
28421
832751
143745672
13900254
172808412
7
2010
1493144
89295
195595
145238816
13989549
173004007
8
2010
1398453
167930
71055
146637269
14157479
173075062
9
2010
1316083
0
437274
147953352
14157479
173512336
10
2010
1278017
0
328573
149231369
14157479
173840909
11
2010
1071872
0
178864
150303241
14157479
174019773
12
2010
1282512
0
118203
151585753"''
14157479'i,174137976'
2010
TOTAL
15544528
894763
4998520
Cumulatives at Dec 31, 2009 136041225 13262716 169139456
Injected Fluid Volumes (Reservoir Units)
Cumulatives at Dec 31, 2009 137945806 15030483 138081429
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
1652158
0
414309
139597964
15030483
138495738
2
2010
1541419
33617
184718
141139383
15064100
138680456
3
2010
1456012
85149
498021
142595395
15149249
139178476
4
2010
891185
509247
462210
143486580
15658495
139640686
5
2010
1061269
73343
777571
144547848
15731839
140418256
6
2010
1210267
32750
683099
145758115
15764589
141101356
7
2010
1514048
102289
159132
147272163
15866878
141260488
8
2010
1418031
189346
57296
148690195
16056224
141317784
9
2010
1334508
0
353434
150024703
16056224
141671218
10
2010
1295909
0
261218
151320612
16056224
141932437
11
2010
1086878
0
141732
152407490
16056224
142074168
12
2010
1300467
0
95173
153707957
16056224''142169341`
2010
TOTAL
15762151
1025741
4087912
Cumulatives at Dec 31, 2009 137945806 15030483 138081429
ATTACHMENT 4
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Reservoir Pressure Surveys
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Tarn Oil Pool — Proposed Pressure Survey Plan for 2011
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
Dear Commissioner Seamount,
In compliance with Rule 8, Conservation Order No. 430A, ConocoPhillips Alaska, Inc., operator of the
Tarn Oil Pool, is hereby submitting the proposed pressure survey plan for 2011.
There were 11 pressure surveys reported for the Tarn Oil Pool to the AOGCC in 2010.
In 2011, we expect to conduct approximately 15 pressure surveys, including initial surveys for new wells
prior to initial sustained production or injection.
If you have any questions concerning this data, please contact Mark Kovar (907) 265-6097.
Sincerely,
dames T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ATTACHMENT 5
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Production Logs and Special Surveys
Two cement bond logs were run on new Tarn development wells.
Well
Date
Comment
2L-326
1/4/2010
New well. TOC @ 6,550'.
2L-310
5/11/2010
New well. TOC @ 7,621'.
A water flow log was run to evaluate upward movement of injection fluids on the 2L -317A
Well
Date
Comment
2L -317A
9/26/2010
No upward flow detected.
Special logs were run to identify leaks and casing corrosion.
Well
Date
Comment
2N-341
8/12/2010
Leaks found at 8,100' and 10,870'.
2N-303
5/31/2010
No definite leaks identified.
2N-303
5/28/2010
Micro Vertilog looking for corrosion.
A flowing temperature and pressure survey was run as part of the 2L-301 paraffin inhibition pilot.
Well
Date
Comment
21--301
8/30/2010
Temp @ chemical inj. mandrel 96 deg.
ATTACHMENT 6
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Results of Well Allocation
Month
Oil
Gas
Water
Jan -10
0.990
0.828
1.059
Feb -10
0.979
0.815
1.029
Mar -10
0.978
0.821
1.016
Apr -10
0.989
0.906
1.068
May -10
0.988
0.900
1.088
Jun -10
0.999
0.888
1.097
Jul -10
0.976
0.922
1.102
Aug -10
0.980
0.899
1.079
Sep -10
0.993
0.876
1.037
Oct -10
0.987
0.896
1.067
Nov -10
1.008
0.915
1.086
Dec -10
0.992
0.902
1.089
ro
ATTACHMENT 7
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Tarn Development Plan and Operational Review
Development Drilling
Well 2L-326, a new grassroots production well drilled from Tarn drillsite 2L targeting the channel to
amalgamated turbidite transition zone in the northeast portion of the drillsite 2N accumulation, was spud
December 12, 2009 and put on production January 31, 2010.
Well 2L-304, a grassroots production well, was spud March 22, 2010 and put on production June 2, 2010.
Well 2L-304 targeted turbidite deposits in the eastern distal portion of the Tarn 2L accumulation. Well 2L-
304 producer is supported by wells 2L-319 and 2L-301, which were converted to miscible water
alternating gas (MWAG) injection in 2009 and 2010, respectively.
Well 2L-310, a grassroots pre -produced injector, was spud on April 25, 2010 and put on production July
2, 2010. The current plan is to pre -produce well 2L-310 until 4th quarter 2011 and then convert to MWAG
injection. Injection well 2L-310 will provide MWAG injection support to existing offset production wells 2L-
307 and 2L-311, and will support new development wells 2L-312 and 2L-306.
The Tarn reservoir model and integration of the 2008 3D seismic data were used to identify and optimize
development targets selected for the 2010 and 2011 drilling programs. The current development drilling
project at drillsite 2L includes drilling two grassroots slant production wells and two grassroots horizontal
producers. The current drilling program began in November 2010 and will continue through April 2011.
Well 2L-312, a grassroots slant production well, was spud on November 27, 2010. Well 2L-312 will be
supported by offset MWAG injectors 2L-305 and 2L-310. As stated above, well 2L-310 was drilled in
2010 as a pre -produced injector and will be converted to MWAG injection during the 4th quarter of 2011.
Well 2L-320, a grassroots slant production well, was spud on December 31, 2010. Well 2L-320 was
drilled in the eastern distal portion of the 2L accumulation and will be supported by offset MWAG injectors
2L-301 and 2L -317A. Well 2L-301 was converted to MWAG injection in December 2010.
Well 2L-306, a grassroots horizontal production well, spud in February 2011. The 2L-306 2,300 ft
horizontal well is currently drilling in the northeastern distal portion of the 2L accumulation. Well 2L-306 is
planned to be completed with six hydraulic fracture treatments along the horizontal section of the
wellbore. Well 2L-306 will be supported by offset injection wells 2L-319 and 2L-310 (well 2L-310 will be
converted to MWAG injection during the 4th quarter of 2011).
In addition to the 2011 development drilling program addressed above, the Tarn development team is
evaluating additional development prospects for future drilling programs.
Producer to Injector Conversions
Well 2L-301 was converted to MWAG injection to provide flood support to offset producing wells 2L-304
and 2L-320 (2L-320 is part of the 2011 development drilling program) located in the eastern distal area of
drillsite 2L.
Conversion plans for 2011 include converting the pre -produced well 2L-310 and producing well 2N-308 to
MWAG injection. Well 2L-310 will provide pressure support and EOR benefit to new offset producers 2L-
312 and 2L-306, while well 2N-308 will provide MWAG injection support to 2N-315 and 2L-326 producing
wells.
Artificial Lift
Tarn was originally designed to use miscible gas (MI) as a means of gas lifting the production wells.
However, paraffin deposition in the tubing string section that runs across the permafrost occurs when the
production fluid temperature falls below the cloud point of 92°F. This is the case of longer reach wells
and lower liquid rate production wells. Excessive paraffin build-up and the high frequency of required
paraffin scrapes in some wells led to a change in artificial lift methodology towards surface -powered
downhole jet pumps. In 2001, after successful pilot tests in 1999 and 2000, 13 of the gas lifted wells were
converted to jet pump using hot produced water as power fluid.
This technique has proven to be very successful in mitigating paraffin deposits. Slickline scrapes and hot
oil treatments have been virtually eliminated leading to production increases of about 10%. Unfortunately
the untreated saline produced water injected down the inner annuli (power fluid) has accelerated tubing
and casing corrosion.
Three well integrity failures occurred on jet -pumped wells due to both tubing and well casing corrosion in
2006-2007: 2L-321, 2N-318 and 2N-305. These wells were shut-in and secured. Wells 2N-305 and 2N-
318 were both sidetracked in 2009. A workover to install an additional casing string was successfully
completed for 2L-321 during 2008.
In 2009 and 2010, three additional wells were shut in after failing mechanical integrity tests: 2N-319, 2N-
303, and 2L-313. Each of these wells was in jet pump service when the failure occurred. These wells will
likely remain secured and shut in until a rotary sidetrack targeting more prolific reservoir is executed. As
of the end of 2010, only three Tarn wells are in jet pump service: 2N-304, 2N-342, and 2L-311.
After water breakthrough occurs in producing wells, paraffin deposition is less likely due to increased well
flowing temperatures (the heat capacity of water is greater than that of oil). In 2011, the remaining three
jet pump wells will be evaluated for gas lift service suitability.
Consequently, completion designs and alternatives to jet pumps are being considered for new and
existing wells. Capillary chemical injection tubes are being installed in new production wells. The capillary
injection lines enable paraffin inhibition chemicals to be injected into the tubing, treating the oil prior to
paraffin deposition. In 2010, a paraffin inhibition pilot test was conducted on well 2L-301. Due to
operational and procedural issues, the results of the pilot test were inconclusive; therefore, another pilot
test may be performed in 2012 to determine the effectiveness of continuous downhole chemical injection.
Depending on the pilot test results, the continuous chemical injection could be expanded to other wells
that have been completed with capillary injection lines.
ATTACHMENT
Tarn Oil Pool
2010 Annual Reservoir Surveillance Report
Map showing recent development wells
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pr
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 West Sak Oil Pool Annual Reservoir Surveillance Report
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 2634027
Fax: (907) 265-6133
In compliance with Rule 11, Conservation Order No. 406A, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Unit, is hereby submitting the annual surveillance report on the West Sak Oil Pool. This
report documents information pertinent to field development and enhanced recovery operations from
January 2010 through December 2010. The following is an outline of the information provided:
a. A summary of the current enhanced oil recovery in the West Sak Oil Pool (Attachment 1).
b. Voidage balance, by month, for produced and injected fluid (Attachments 2 and 3).
c. Analysis of reservoir pressure surveys taken in 2010 and pressure survey plans for 2011
(Attachment 4).
d. Results of injection surveys, production surveys, and any special surveys, conducted in the West
Sak Oil Pool in 2010 (Attachments 5 through 7).
e. Results of pool production allocation factors (Attachment 8).
f. Future development plans (Attachment 9).
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
Z -V
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ATTACHMENT 1
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Summary of the Enhanced Oil Recovery Project
. There were no new wells placed in service in the West Sak Oil Pool in 2010.
• Well 1D-126 was suspended due to a casing leak to surface in April 2010. Asa result of this casing leak,
• twenty-seven injectors surrounding single casing producers were shut-in in June 2010 pending the
installation of a second barrier in the producers. Select injectors may be returned to service in 2011 for
• reservoir management reasons, but the majority of the wells will remain shut in throughout the year.
Waterflooding the reservoir for pressure maintenance and improved sweep continues to be the main
enhanced oil recovery mechanism in the West Sak oil pool. Drill Sites 1 B, 1C, 1D and 1J inject CPF-1
produced water while Drill Site 3K injects seawater. The injectors on Drill Site 1 E were swapped from
produced water to seawater injection in August 2010. There have been no injection issues to date as a
result of the change. Waterflood performance was good in the majority of the West Sak patterns. During
2010 the West Sak oil pool experienced one rapid water breakthrough event and identified a second
connection that was initiated in March 2007. Further diagnostic work on a Matrix Bypass Event that
occurred in December 2009 was also completed. These events create highly conductive pathways
between an injector and a producer. A list of the matrix bypass events identified in 2010 is provided
below:
Injector
Producer
Event Date
Breakthrough Zone
1D-111
1 C-104
March 2007
B Sand
1 E-102
1 E-121
December 2009
D Sand*
1J-136
1J-135
February 2010
B Sand
*The 2009 Surveillance Report showed a matrix bypass event from 1E-102 to 1E-123. Diagnostics
indicate that the matrix bypass event is from IE -102 to IE -121.
Analysis and review of the bypass events is an ongoing activity. Measures to mitigate future matrix
bypass events were implemented in 2005 and 2007 resulting in reductions in the frequency of new
bypass events. In addition, remediation repairs were implemented in 2010 that successfully isolated two
bypass events. A new remediation strategy was attempted on two wells in 2010. Two more attempts
with the new technology are planned for 2011.
During 2003, ConocoPhillips Alaska, Inc. received approval to commence a West Sak Small Scale EOR
(SSEOR) Pilot Project using Kuparuk MI in a water -alternating gas (WAG) pilot. The SSEOR Pilot Project
is completed. In 2009, a West Sak Viscosity Reducing Water Alternating Gas (VRWAG) Pilot project was
approved for four West Sak injectors at 1 E and 1J. Initial VRWAG gas injection began in November 2009
in two injectors, 1E-102 and 1E-117. Two additional injectors, 1J-170 and 1J-122 began gas injection in
April 2010. Well 1 E-102 was shut-in following a matrix bypass event with 1 E-121. Well 1 E-102 has been
removed from the VRWAG pilot project. No breakthroughs have been detected in the three remaining
patterns. To date, none of the four targeted patterns is mature enough in the VRWAG process to show
definitive results.
ATTACHMENT 2
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Produced Fluid Volumes
Cumulatives at Dec 31, 2009 45073160 22055374 11085643
Produced Fluid Volumes (Reservoir Units)
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
STB
MSCF
STB
STB
MSCF
STB
1
2010
436288
153601
245506
45509448
22208975
11331149
2
2010
401522
146781
200901
45910970
22355756
11532050
3
2010
410089
141915
288584
46321059
22497671
11820634
4
2010
420825
149183
233138
46741884
22646854
12053772
5
2010
462850
165209
185625
47204734
22812063
12239397
6
2010
399832
173027
146667
47604566
22985090
12386064
7
2010
497118
191988
191608
48101684
23177078
12577672
8
2010
535792
193165
186294
48637476
23370243
12763966
9
2010
487347
165358
156562
49124823
23535601
12920528
10
2010
412881
185967
186868
49537704
23721568
13107396
11
2010
473347
216376
204135
50011051
23937944
13311531
12
2010
468708
227911
179829,5
9159
2165$55 ;7349360 ',
X13491360
2010 TOTAL
5406599
2110481
2405717
2405717
Cumulatives at Dec 31, 2009 45073160 22055374 11085643
Produced Fluid Volumes (Reservoir Units)
Cumulatives at Dec 31, 2009 48176244 20523249 11085643
OIL
GAS
WATER
CUM OIL
CUM GAS
CUM WATER
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
465956
114227
245506
48642200
20637476
11331149
2
2010
428825
114796
200901
49071025
20752272
11532050
3
2010
437975
106342
288584
49509000
20858613
11820634
4
2010
449441
117124
233138
49958441
20975737
12053772
5
2010
494324
124884
185625
50452765
21100622
12239397
6
2010
427021
157454
146667
50879786
21258076
12386064
7
2010
530922
161989
191608
51410708
21420065
12577672
8
2010
572226
155606
186294
51982933
21575671
12763966
9
2010
520487
124665
156562
52503420
21700335
12920528
10
2010
440957
184783
186868
52944377
21885118
13107396
11
2010
505535
211685
204135
53449912
22096803
13311531
12
2010
500580
227917
179829
33950492 '
2232 720
X13491360
2010 TOTAL
5774248
1801471
2405717
Cumulatives at Dec 31, 2009 48176244 20523249 11085643
ATTACHMENT 3
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Injected Fluid Volumes
2010 TOTAL 5856623 8180 674928
Cumulatives at Dec 31, 2009 67628539 0 559061
Injected Fluid Volumes (Reservoir Units)
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
STB
MSCF
MSCF
STB
MSCF
MSCF
1
2010
700133
0
43235
68328672
0
602296
2
2010
674363
0
51790
69003035
0
654086
3
2010
662019
0
21771
69665054
0
675857
4
2010
681083
0
99932
70346137
0
775789
5
2010
595426
8180
94010
70941563
8180
869799
6
2010
393331
0
94627
71334894
8180
964426
7
2010
441966
0
41102
71776860
8180
1005528
8
2010
372833
0
0
72149693
8180
1005528
9
2010
369719
0
23908
72519412
8180
1029436
10
2010
324327
0
51685
72843739
8180
1081121
11
2010
327328
0
55929
73171067
8180
1137050
12
2010
314095
0
96939
j3485162, ..81 80 . 233989
2010 TOTAL 5856623 8180 674928
Cumulatives at Dec 31, 2009 67628539 0 559061
Injected Fluid Volumes (Reservoir Units)
2010 TOTAL 5856623 13382 505521
Cumulatives at Dec 31, 2009 67628539 0 418737
WATER
GAS
MI
CUM WATER
CUM GAS
CUM MI
MO
YR
RVB
RVB
RVB
RVB
RVB
RVB
1
2010
700133
0
32383
68328672
0
451120
2
2010
674363
0
38791
69003035
0
489911
3
2010
662019
0
16306
69665054
0
506217
4
2010
681083
0
74849
70346137
0
581066
5
2010
595426
13382
70413
70941563
13382
651480
6
2010
393331
0
70876
71334894
13382
722355
7
2010
441966
0
30785
71776860
13382
753141
8
2010
372833
0
0
72149693
13382
753141
9
2010
369719
0
17907
72519412
13382
771048
10
2010
324327
0
38712
72843739
13382
809760
11
2010
327328
0
41891
73171067
13382
851651
12
2010
314095
0
72607
W734851$2'1,17'
3382.... 924258''
2010 TOTAL 5856623 13382 505521
Cumulatives at Dec 31, 2009 67628539 0 418737
ATTACHMENT 4
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Reservoir Pressure Surveys
Perforated Intervals and Stratigraphic Zones
Proposed Pressure Survey Plan for 2010
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: West Sak Oil Pool — Proposed Pressure Survey Plan for 2011
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
Dear Commissioner Seamount,
In compliance with Rule 8, Conservation Order No. 406A, ConocoPhillips Alaska, Inc., operator of the
West Sak Oil Pool, is hereby submitting the proposed pressure survey plan for 2011.
There were 19 pressure surveys reported for the West Sak Oil Pool to the AOGCC in 2010.
In 2011, we expect to conduct approximately 20 pressure surveys, including initial surveys for new wells
prior to initial sustained production or injection.
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
j IIS
gJaynes T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
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ATTACHMENT 6
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Production Survey Data
During 2010, no production profile survey was attempted for the West Sak Oil Pool.
ATTACHMENT 7
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Special Survey Date
Geochemcial Oil Production Splits
Well Name
Sample Date
A Sand
B Sand
D Sand
1 C-102
04/17/10
0%
33%
67%
1 C-102
08/06/10
0%
5%
95%
1 C-109
04/17/10
0%
27%
73%
1 C-109
08/06/10
0%
26%
74%
1 C-178
07/23/10
0%
39%
62%
1C-184
04/17/10
0%
0%
100%
1 D-1 05A
04/01/10
0%
0%
100%
1 D-108
04/22/10
36%
29%
35%
1 D-112
04/22/10
42%
29%
29%
1 D-112
08/05/10
46%
29%
26%
1D-113
04/21/10
44%
20%
36%
1 D-113
08/05/10
39%
26%
35%
1 D-115
08/05/10
45%
32%
23%
1 D-118
04/20/10
74%
0%
26%
1D-122
02/05/10
2%
3%
95%
1 D-123
04/20/10
48%
25%
27%
ID -123
07/26/10
49%
24%
26%
1D-124
04/19/10
41%
40%
20%
1 D-124
04/27/10
43%
39%
19%
1D-124
07/26/10
48%
31%
21%
1D-129
04/17/10
60%
31%
9%
1D-129
08/05/10
53%
34%
13%
1 D-131
07/26/10
52%
49%
0%
1 D-133
04/21/10
63%
18%
20%
1 D-133
07/26/10
67%
10%
24%
1 D-134
04/22/10
57%
25%
18%
1 D-134
07/26/10
65%
23%
13%
1 D-135
04/22/10
15%
28%
58%
1 D-135
07/26/10
5%
30%
65%
1E-112
01/21/10
0%
100%
0%
1 E-117
07/28/10
41%
25%
34%
1E-121
04/22/10
0%
15%
85%
1E-121
08/01/10
0%
16%
84%
1E-123
08/01/10
0%
24%
76%
1E-126
04/22/10
8%
44%
49%
1E-166
04/22/10
6%
83%
11%
1E-166
08/01/10
9%
90%
2%
1E-168
04/22/10
0%
38%
62%
1E-168
08/01/10
0%
35%
65%
1 E-170
04/22/10
0%
12%
89%
1E-170
08/01/10
0%
53%
47%
1J-101
04/21/10
21%
42%
38%
1J-101
08/03/10
35%
43%
23%
1 J-103
04/22/10
0%
45%
56%
1 J-103
08/03/10
0%
54%
46%
1J-107
01/26/10
0%
3%
97%
1J-107
08/03/10
0%
61%
40%
1J-115
04/21/10
15%
34%
51%
1 J-115
08/03/10
17%
33%
51%
1 J-118
08/04/10
0%
49%
51 %
ATTACHMENT 7
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Special Survey Date
Geochemcial Oil Production Splits
U-118
10/01/10
21%
47%
32%
U-120
04/17/10
4%
20%
76%
U-120
08/03/10
4%
13%
84%
1 J-135
04/17/10
0%
73%
28%
1J-135
08/03/10
0%
32%
68%
1J-136
04/07/10
0%
0%
100%
U-152
04/20/10
17%
51%
32%
U-152
08/03/10
24%
23%
53%
U-158
08/03/10
0%
67%
33%
1J-159
04/21/10
23%
12%
66%
1J-159
08/03/10
26%
6%
68%
1J-160
04/11/10
0%
0%
100%
U-162
08/03/10
0%
8%
92%
U-166
04/16/10
15%
33%
52%
U-166
08/03/10
18%
32%
50%
1J-168
04/27/10
11%
83%
7%
1 J-168
08/03/10
14%
77%
9%
U-174
04/19/10
0%
53%
47%
U-174
08/03/10
0%
55%
45%
1J-176
08/18/10
0%
89%
11%
1J-178
04/18/10
0%
59%
41%
U-178
08/29/10
0%
67%
33%
U-182
08/03/10
0%
52%
48%
ATTACHMENT 8
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Allocation Factors
Month
Oil
Gas
Water
Jan -10
0.990
0.828
1.059
Feb -10
0.979
0.815
1.029
Mar -10
0.978
0.821
1.016
Apr -10
0.989
0.906
1.068
May -10
0.988
0.900
1.088
Jun -10
0.999
0.888
1.097
Jul -10
0.976
0.922
1.102
Aug -10
0.980
0.899
1.079
Sep -10
0.993
0.876
1.037
Oct -10
0.987
0.896
1.067
Nov -10
1.008
0.915
1.086
Dec -10
0.992
0.902
1.089
ATTACHMENT 9
West Sak Oil Pool
2010 Annual Reservoir Surveillance Report
Future Development Plans
• WEST SAK DEVELOPMENT
The Kuparuk River Unit working interest owners have no identified plan to progress drilling opportunities
in 2011. A three to five well West Sak infill program is being evaluated for 2012. In addition, a 3K
development producer is under evaluation as an offset to the 3K Phase 1 development. The infill wells
are expected to be vertical completions with the 3K well being a multi -lateral horizontal completion.
Timing depends on rig availability and the economic business climate.
• EASTERN NORTHEAST WEST SAK (EASTERN NEWS) DEVELOPMENT
The Kuparuk River Unit working interest owners have re -started the Eastern NEWS development
planning work that was suspended in 2008. If a viable development plan is identified, current plans are to
present it to corporate management in 2012.
• UGNU PILOTS/ STUDIES
Unit owners are evaluating the installation of an induction heater into well 1H-401 in late 2011. The
objective is to produce the well in order to obtain an uncontaminated oil sample. Should the heater allow
sustained production, it would likely remain on production in order to test the long term viability of the
heater.
The Unit owners are also re -starting the feasibility studies and engineering for a thermal pilot in the area.
Current plans are to evaluate the scope of a pilot project and identify the required design and
technologies needed to submit the project to management by late 2012.
y
01
ID
ConocoPhillips
March 31, 2011
Mr. Dan Seamount, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: 2010 Allowable Gas Offtake from Kuparuk River Oil Pool
Dear Commissioner Seamount,
James T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1326
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 263-4027
Fax: (907) 265-6133
In compliance with Rule 13, Conservation Order No. 432D, ConocoPhillips Alaska, Inc., operator of the
Kuparuk River Oil Pool, is hereby submitting the gas offtake volume information for 2010 (Attachment 1).
During 2010, the annualized average gas offtake was 2,028 MSCFD, considerably less than the
maximum allowable annual average gas offtake rate of 5 MMSCFD as stated in Rule 13 for Kuparuk
River Oil Pool.
If you have any questions concerning this data, please contact Mark Kovar at (907) 265-6097.
Sincerely,
`—d'ames T. Rodgers
Manager, GKA Development
Greater Kuparuk Area
Attachment 1
Kuparuk River Oil Pool
2010 Annual Reservoir Surveillance Report
Gas Offtake Data
4000
3500
3000
2500
MCFD 2000
1500
1000
Kuparuk Gas Offtake -2010
500M
2010 Monthly
Gas Offtake
0
MSCFD
SCFD
RBID
January
1740
1740387
1537
February
1333
1333393
1177
March
1277
1276581
1127
April
1247
1247033
1101
May
1085
1084581
958
June
1042
1041500
920
July
1278
1277742
1128
August
2281
2281419
2014
September
3605
3605467
3184
October
1163
1163065
1027
November
1090
1089500
962
December
547
547097
483
Average
1,474
1,473,980
1,302
4000
3500
3000
2500
MCFD 2000
1500
1000
Kuparuk Gas Offtake -2010
500M
0
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