Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAbout2008 Colville River UnitRE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
2
cc:
Mr. Tom Irwin, Commissioner
Alaska Department of Natural Resources
550 W. 7th Ave., Suite 800
Anchorage, AK 99501-3035
Mr. Kevin Banks, Acting Director
Alaska Department of Natural Resources
550 W. 7th Ave. Suite 800
Anchorage, AK 99501
Ms. Temple Davidson, Petroleum Land
Manager
Alaska Department of Natural Resources
550 W. 7th Ave. Suite 800
Anchorage, AK 99501
Mr. Mike Kotowski
Alaska Department of Natural Resources
550 W. 7th Ave., Suite 1100
Anchorage, AK 99501
Ms. Roberta Quintavell, President
Arctic Slope Regional Corporation
PO Box 129
Barrow, AK 99723-0129
Ms. Teresa Imm, Resource Development
Manager
Arctic Slope Regional Corporation
3900 C Street, Suite 801
Anchorage, AK 99503-5963
Arctic Slope Regional Corporation
Attention: Land Department
3900 C Street, Suite 801
Anchorage, AK 99503-5963
Mr. Isaac Nukapigak, President
Kuukpik Corporation
PO Box 89187
Nuiqsut, AK 99789
Mr. Steve Dodds, Landman
Anadarko Petroleum Corporation
1201 Lake Robbins Drive
The Woodlands, TX 77380
Mr. Joe Martin
Anadarko Petroleum Corporation
1201 Lake Robbins Drive
The Woodlands, TX 77380
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
3
bcc:
Chris Wilson ATO-1770
Jack Walker ATO 1742
Brian Barreda ATO-1738
Dora Soria ATO 1468
Alpine General File 1.2.4
CPAI Central Files
2008 Annual Reservoir Surveillance Report, Alpine Oil Pool
and
2008 Annual Reservoir Review, Fiord, Nanuq, Nanuq-Kuparuk, and
Qannik Oil Pools
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
i
Table of Contents
Table of Contents.........................................................................................................................i
Alpine Oil Pool ............................................................................................................................1
1.0 Progress of Recovery Projects............................................................................................1
1.1 Average Metrics for 2008 ....................................................................................................1
1.2 Cumulative Volumes Produced and Injected in 2008..........................................................1
1.3 Miscible Water Alternating Gas Flood Management During 2008 ......................................1
CD1........................................................................................................................................1
CD2........................................................................................................................................2
1.4 MI Enrichment Challenges ..................................................................................................2
1.5 Reservoir Management.......................................................................................................3
1.6 Water Injection Challenges .................................................................................................4
2.0 Alpine Production and Injection by Month.........................................................................4
3.0 Survey Results......................................................................................................................5
3.1 Reservoir Pressure Monitoring............................................................................................5
3.2 Well Surveillance.................................................................................................................5
4.0 Surveys and Survey Results................................................................................................5
5.0 Field Development................................................................................................................5
5.1 Development Wells Drilled as of March 31, 2009 ...............................................................5
5.2 Development Drilling Completed in 2008............................................................................6
5.3 Fracture Stimulations in 2008..............................................................................................6
5.4 Development Drilling in 2009 ..............................................................................................6
5.5 Facilities Expansion Evaluation Results and Update ..........................................................7
ACX Phase 1.........................................................................................................................7
ACX Phase 2.........................................................................................................................7
ACX Phase 3.........................................................................................................................7
Emergency Power Upgrade .......................................................................................................7
Alpine Water Handling Project ..................................................................................................8
Conclusion ..................................................................................................................................8
Nanuq Oil Pool............................................................................................................................9
Overview of Reservoir Performance .........................................................................................9
Future Development and Reservoir Depletion Plans ................................................................9
Surveillance Information............................................................................................................9
Nanuq-Kuparuk Oil Pool ..........................................................................................................10
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
ii
Overview of Reservoir Performance .......................................................................................10
Future Development and Reservoir Depletion Plans ..............................................................10
Surveillance Information..........................................................................................................10
Fiord Oil Pool ............................................................................................................................11
Overview of Reservoir Performance .......................................................................................11
Future Development and Reservoir Depletion Plans ..............................................................11
Surveillance Information..........................................................................................................11
Qannik Oil Pool.........................................................................................................................12
Future Development and Reservoir Depletion Plans ..............................................................12
Surveillance Information..........................................................................................................12
Attachment 1: CRU Boundary effective as of August 15, 2005............................................14
Attachment 2: All Wells Drilled as of January 1, 2009...........................................................15
Attachment 3: MWAG conversion status at CD1...................................................................18
Attachment 4: MWAG maturity CD1........................................................................................19
Attachment 5: MWAG conversion status at CD2...................................................................20
Attachment 6: MWAG maturity at CD2....................................................................................21
Attachment 7: Recovery - throughput response at Alpine ...................................................22
Attachment 8: Alpine Form 10-412 Reservoir Pressure Report ...........................................23
Attachment 8 (continued): Alpine Form 10-412 Reservoir Pressure Report.......................24
Attachment 8 (continued): Alpine – Kuparuk Undefined Oil Pool Form 10-412 Reservoir
Pressure Report........................................................................................................................25
Attachment 9: Nanuq and Nanuq-Kuparuk Reservoir Pressure Map at Datum..................26
Attachment 10: Nanuq Form 10-412 Reservoir Pressure Report.........................................27
Attachment 11: Nanuq Estimate of Yearly Production and Reservoir Voidage Balance...28
Attachment 12: Results of Safety Valve System Testing, CD2.............................................29
Attachment 12 (continued): Results of Safety Valve System Testing, CD3........................30
Attachment 12 (continued): Results of Safety Valve System Testing, CD3........................31
Attachment 12 (continued): Results of Safety Valve System Testing, CD3........................32
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................33
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................34
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................35
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................36
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................37
Attachment 12 (continued): Results of Safety Valve System Testing, CD4........................38
Attachment 13: Nanuq-Kuparuk Form 10-412 Reservoir Pressure Report .........................39
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
iii
Attachment 14: Nanuq-Kuparuk Estimate of Yearly Production and Reservoir Voidage
Balance......................................................................................................................................40
Attachment 15: Fiord Reservoir Pressure Map at Datum......................................................41
Attachment 16: Fiord Form 10-412 Reservoir Pressure Report ...........................................42
Attachment 17: Fiord Estimate of Yearly Production and Reservoir Voidage Balance.....43
Attachment 18: Qannik Reservoir Pressure Map at Datum ..................................................44
Attachment 19: Qannik Form 10-412 Reservoir Pressure Report........................................45
1
2008 Annual Reservoir Surveillance Report
Alpine Oil Pool
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
1
Alpine Oil Pool
Conservation Order 443A, Rule 8 requires this Annual Reservoir Surveillance Report.
Attachment 1 illustrates the current unit boundary, which was revised in August 2005.
Attachment 2 lists Alpine wells drilled as of March 31, 2009.
1.0 Progress of Recovery Projects
1.1 Average Metrics for 2008
-Average oil production rate.............................................................67.8 MBOPD
-Average gas production rate...........................................................103.3 MMSCFD
-Average water production rate........................................................16.7 MBWPD
-Average gas injection rate..............................................................100.4 MMSCFD
-Average water injection rate ...........................................................95.5 MBWPD
1.2 Cumulative Volumes Produced and Injected in 2008
-Cumulative oil production through December 2008:.......................284,896,750 STBO
-Cumulative gas production through December 2008: ....................343,985,937 MSCF
-Cumulative water production through December 2008: .................18,793,608 STBW
-Cumulative gas injection through December 2008:........................310,314,895 MSCF
-Cumulative water injection through December 2008:.....................294,319,586 STBW
1.3 Miscible Water Alternating Gas Flood Management During 2008
Development of the Alpine reservoir is based on a Miscible Water Alternating Gas (MWAG)
project design. Alpine EOR facilities have been described in previous testimony before the
AOGCC. This discussion will provide a narrative update on key reservoir management issues
for the time period of January 2008 through January 2009.
CD1
Attachment 3 gives an overview of the miscible water alternating gas (MWAG) conversion
status at CD1 in a tabular form. The MWAG flood has significantly matured at CD1, as shown in
Attachment 4. CD1 averages a hydrocarbon pore volume (HCPV) throughput of approximately
91 percent among the 22 MWAG injectors. Nine wells have completed the target MI slug of
approximately 30 percent HCPV (CD1-03, CD1-05, CD1-07, CD1-11, CD1-21, CD1-23, CD1-
26, CD1-31, & CD1-39). Nineteen wells have completed or are on their second cycle of MI, after
having been temporarily converted to seawater injection in order to alleviate rising gas-oil ratio
(GOR) trends in offset producers. Fourteen wells have completed or are on their third cycle of
MI. Eight wells, CD1-01, CD1-02, CD1-03, CD1-13, CD1-16, CD1-26, CD1-31, and CD1-42
have completed or are on their fourth cycle of miscible injectant (MI). CD1-01 is the only well
that has begun a fifth cycle of MI at this time. Four wells at CD1 were converted to lean gas
injection in 2008; CD1-03, CD1-07, CD1-13, and CD1-23. Nineteen MWAG injectors have
completed or are on their second cycle of seawater injection. Nineteen wells have completed or
are on their third cycle of seawater injection and eleven wells have completed or are on their
fourth cycle of seawater injection. Seven wells, CD1-01, CD1-02, CD1-03, CD1-07, CD1-13,
CD1-26, and CD1-42, are on or have completed their fifth cycle of seawater injection.
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
2
The main drivers behind the rate of maturation of the different patterns are field offtake, local
voidage balance requirements, seawater availability, MI enrichment requirements and the
necessity to control GOR within compressor limits.
CD2
An overview of the MWAG conversion status can be found on Attachment 5 in a tabular form.
The maturity of the different injection centered patterns at CD2 is illustrated on Attachment 6.
CD2 is significantly less mature than CD1, with only 46 percent overall throughput. This is due
to a combination of factors: Production started up later than at CD1, and the off take and
throughput rates at CD2 were lower due to ongoing development drilling. Also, larger reserves
are present at CD2 and the poorer rock quality will not allow the same throughput rates as seen
at CD1. Eight wells have completed the target MI slug of approximately 30 percent HCPV (CD2-
07, CD2-08, CD2-11, CD2-12, CD2-22, CD2-26, CD2-29, & CD2-44). Thirty-one MWAG
injectors are in place at CD2. Only two injectors are on their first cycle of seawater injection.
Thirty wells have completed or are on their first cycle of MI injection. Twenty-one wells have
completed or are on their second cycle of MI injection. Twenty-nine wells have completed or are
on their second cycle of seawater injection. Twenty-one wells are currently on their third cycle of
seawater injection and fourteen wells are on their third cycle of MI. Eleven wells are on or have
completed their fourth cycle of seawater injection and three (CD2-06, CD2-07, and CD2-29) are
on their fifth. Two wells at CD2 were converted to lean gas injection and are on or have
completed their second slug of lean gas (CD2-06 & CD2-07). Of the 31 MWAG injectors at CD2,
only one has not started the first MI slug (CD2-60) due to extremely low injectivity.
Eight injection wells (CD2-02, CD2-11, CD2-18, CD2-54, CD2-56, CD2-59, CD2-60, and CD4-
17) have been completed in the Alpine A sand. These wells are on or have completed their first
cycle of MI injection with the exception of CD2-60. No problems with injectivity have been
observed while on water or gas and a good response by offset producers completed in the A
sand suggest that this sand should deliver similar recovery factors as seen in the C sand.
Overall field response to the MWAG remains excellent. Attachment 7 shows the recovery-
throughput relation from all active Alpine MWAG patterns, and attests to the effectiveness of the
enhanced oil recovery (EOR) flood at Alpine.
1.4 MI Enrichment Challenges
The MI stream is manufactured at the Alpine Central Facility (ACF) by blending lean gas from
the field gas production stream (blend gas) with C2+ enriching components extracted from
either the condensate flash drum (when stabilizer is offline) or the stabilizer reflux drum (when
stabilizer is in operation). The composition of the MI is routinely monitored and adjusted to
ensure miscibility with the reservoir oil. With the start of MWAG injection at CD3 and CD4, the
MI must now also meet the minimum miscibility pressure (MMP) requirements of the crude oils
in the reservoirs flooded from those drill sites.
All lean gas handled at the ACF must either be 1) used as fuel, 2) blended into MI, or 3) injected
as lean gas. The rate of fuel gas consumption is fixed by the ACF heating and electrical
generating needs. The amount of lean gas blended into MI is controlled by the amount of
enriching fluid available. If the amount of lean gas blended into MI decreases in order to
maintain the blend at the required MMP, then more lean gas must be injected.
With the commissioning of the Gas Condensate Stabilizer Unit in December 2006, the MI
enrichment process has taken on an added level of complexity. The stabilizer, as the name
implies, stabilizes C5+ components for additional crude sales. This process can reduce the
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
3
amount of enriching fluid available for MI manufacture, thus impacting the overall volume of MI
produced at any given MMP spec and the amount of lean gas remaining after blending.
In 2007, a team studied the cause-and-effect relationship between gas production, enriching
fluid availability, stabilizer operation, MI manufacture, and long term EOR performance. As a
result of their evaluation, several mature MWAG injectors were converted from long-term water
injection service (which is the standard late-term phase of the MWAG flood) to long-term lean
gas injection. This increased lean gas injection capacity was required in order to handle the
extra amount of lean gas requiring injection which allowed for the maximum amount of
production possible during this timeframe.
The initial view from the 2007 study was that over time, as more MWAG injectors reach their
target MI injection volume and switch to post-MWAG water flood chase, some would need to be
converted to lean gas injection (either continuous “LGI” or “IWAG”) to meet the underground
storage required for the unblended lean gas. This would then maximize production by
minimizing the number of wells that would have to be shut-in for gas handling. However thru the
course of 2008 the amount of lean gas has increased markedly and now makes up almost 50%
of the total gas injection volume. Thus, MI production is considerably down while demand from
the satellites has ramped up as those MWAG floods continue to mature. In addition,
containment of the lean gas injection into the mature CD1 area patterns has become very
difficult and lean gas is starting to affect some producers. To date the impact has been mostly
positive with very strong EOR response being observed however with the GORs continuing to
rise these producers will inevitably get shut-in due to high producing GORs. The preliminary
modeling efforts in 2008 have indicated favorable recoveries can be achieved with lower blend
ratio injectant. Additional modeling work will be progressed in 2009 to evaluate WAG options at
WNS to reduce the lean gas injection into CD1 in 2009.
1.5 Reservoir Management
For the duration of 2008, ACF shared the production and injection facilities with Fiord and
Nanuq. In addition to these two existing satellites, the Qannik development was brought online
mid-year and also shared in the ACF production and injection facility capacities. This maximized
the overall oil production rate from the combined developments.
In 2009 reservoir management of the main Alpine field will concentrate on maximizing oil
production rate by targeting a pattern injection/withdrawal ratio of one, injection capacity
permitting. To the extent that producing GORs can be reduced, oil rate will be maximized,
especially in the summer months when gas compression capacity is reduced by warmer
ambient temperatures. Productivity will be increased by hydraulically fracturing up to three
Alpine producers. Now that core Alpine development drilling is complete, production rate is
expected to continue to decline throughout 2009.
The satellite demand for injection water averaged approximately 37 MBWPD in 2008. Satellite
demand will continue to increase in 2009 to approximately 46 MBWPD. Total water production
is expected to rise during the year, bringing the volume of water available for injection (produced
water plus imported water from the Greater Kuparuk Area) close to the current available water
injection capacity of 150,000 BWPD. High satellite productivity has caused increased short term
injection demand. Further, revised ConocoPhillips best practices around water injection systems
operating practices have led to increased restriction around the plan to mix produced and
injection water. To mitigate the above, CPAI plans to install additional manifolding and pumping
capacity to allow segregation of produced and seawater injection to all drill sites and increased
injection volumes. Installation is expected to be complete by late 2009 (see Water Injection
Challenges section below)
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
4
1.6 Water Injection Challenges
The water injection system at Alpine consists primarily of three 50 MBWPD injection pumps.
Currently, two of the pumps take seawater imported from the Seawater Treatment Plant (STP),
in the Kuparuk River Unit, and one pump takes produced water and seawater and sends this
mixed water to CD1 and CD3. The demand for water from the seawater pumps has increased
with the addition of the satellites. Drilling results at the satellites have lead to increased injection
demand than predevelopment estimates. This was due to higher than expected Kuparuk
performance at Nanuq and Fiord as well as lower than expected Nanuq Nanuq performance.
Additionally the desire to mitigate against corrosion in the water injection lines prevents long
term mixing of all waters at Alpine and thus reduces the water injection system’s flexibility. A
team has implemented a short solution which includes limited mixing, a jumper line to CD3, pig
launger/receiver facilities, corrosion and scale inhibitor injection points, and smart-pigging during
March/April 2009. The long term solution includes the installation of two ESP pumps, additional
manifolding to the pump, and additional manifolding to all CDs which will provide flexibility to
segregate water and better direct distribution of seawater and produced water to each of the
CDs. This long term projects to enhance the flexibility of the current system while mitigating
corrosion risks.
2.0 Alpine Production and Injection by Month
Total
Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj
MSTBO MMSCF MSTBW MSTBW MMSCF MMSCF MMSCF
1/31/2008 2,412.7 3,688.7 447.5 3,148.2 1,540.9 1,804.1 3,345.0
2/29/2008 2,125.0 3,295.6 398.5 3,154.7 1,354.1 1,528.4 2,882.5
3/31/2008 2,319.7 3,775.1 518.8 2,883.2 1,855.2 1,578.3 3,433.6
4/30/2008 2,230.1 3,854.2 474.5 3,033.0 2,102.3 1,397.7 3,500.0
5/31/2008 2,218.5 3,725.1 521.2 2,987.0 1,949.2 1,562.5 3,511.7
6/30/2008 2,094.3 3,280.9 477.1 2,916.8 1,503.6 1,612.6 3,116.3
7/31/2008 2,181.3 3,392.6 479.6 2,943.9 1,394.6 2,021.0 3,415.5
8/31/2008 1,089.5 1,696.3 289.9 2,024.8 771.8 973.1 1,744.8
9/30/2008 2,218.2 3,068.4 613.4 2,825.7 1,344.0 1,611.9 2,955.9
10/31/2008 2,153.3 3,175.9 639.0 3,048.1 1,472.7 1,649.0 3,121.7
11/30/2008 2,012.1 3,067.4 607.9 3,052.3 1,522.4 1,230.0 2,752.4
12/31/2008 2,033.7 3,274.8 652.1 2,931.9 1,623.7 1,315.0 2,938.8
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
5
3.0 Survey Results
3.1 Reservoir Pressure Monitoring
Several pressure surveys were conducted on Alpine wells during the course of operations in
2008. The reservoir is continuously being managed to allow for local pressure build up in areas
of historic under injection while maintaining average pattern pressures at or above the level
required for stable production and optimum EOR performance in the rest of the field. Reservoir
pressures are estimated from the Alpine full field simulation model as well as from inflow
performance relation analysis on all drilled producers. Both approaches are calibrated with
actual reservoir pressure measurements collected from static surveys taken in development
wells. The Reservoir Pressure Report (Form 10-412) for Alpine is provided in Attachment 8.
3.2 Well Surveillance
Thirty-one Alpine wells had reservoir pressure measured via static pressure survey in 2008.
In late 2007 and early 2008, routine well surveillance uncovered numerous CD2 production
wells with very significant rates of decline. A significant number of these cases could be
explained by pressure depletion mechanisms; however, several cases had no other explanation
at the time. The potential for near-wellbore barium sulfate scale formation soon came to the
forefront as a possible explanation. Historic scale monitoring efforts had mainly focused on the
tubulars and surface equipment and had always pointed to a very minor tendency. A new effort
was initiated early in 2008 to evaluate these suspect wells and ascertain whether or not near-
wellbore scaling was occurring. Several gamma-ray logs were run in suspect wells to detect
whether the naturally radioactive scale was present. The presence of near-wellbore scale was
confirmed in all wells exceeding five percent watercut and a few downhole samples of the
barium sulfate scale were recovered. Following these discoveries, a downhole scale squeeze
program was developed to treat producers in the early stages of water breakthrough. The scale
inhibition program is based on the 2003-04 Alpine core work that evaluated various scale
inhibitors. Four squeezes were performed on Alpine wells in 2008 and up to thirty-five are
planned in 2009. Confirmation of near wellbore scale impacts on production are not conclusive,
but will be further investigated in 2009.
Eleven fracture stimulations were performed in 2008 and resulted in appreciable production rate
increases. Based on fracturing success at Alpine, additional stimulations are planned for 2009.
4.0 Surveys and Survey Results
There were no special surveys taken during 2008.
5.0 Field Development
5.1 Development Wells Drilled as of March 31, 2009
• 110 wells drilled total:
o 22 CD1 producers
o 22 CD1 injectors
o 29 CD2 producers
o 32 CD2 injectors
o 3 CD4 Alpine producers
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
6
o 1 CD4 Alpine Injector
o 2 disposal wells
5.2 Development Drilling Completed in 2008
All Alpine wells planned for initial development of the main field from CD1 and CD2 have been
drilled and completed as of November 2005. Since that time peripheral development well
targets have been developed in conjunction with the satellite drilling program. In 2006, CD4-17
was drilled from CD4 as part of a planned 2-well development of a single injector/producer
pattern in the southwest corner of the Participating Area (PA). The producer, CD4-16 was drilled
and completed in late 2006 and found initial oil saturations present. Three wells were drilled and
completed as A Sand producers in 2007: CD2-72, CD4-05 and CD4-07. CD4-05 found an
unexpected pocket of C sand 100’ above the A sand. The well was completed in both the Alpine
A sand and Alpine C sand. The deviated 20’ section of Alpine C sand is producing
approximately 1000 BOPD. A single A Sand development well was drilled in 2008 from CD2
along with CD2-75, drilled north of CD4-07.
5.3 Fracture Stimulations in 2008
Ten fracture stimulations were performed in 2008 on CD1-27, CD1-28, CD1-34, CD1-35, CD1-
40, CD1-44, CD2-39, CD2-41, CD4-05 and CD4-16 that resulted in appreciable production rate
increases and reserve adds. Based on these results, plans are to stimulate additional wells in
2009.
5.4 Development Drilling in 2009
Additional Alpine A Sand opportunities are being evaluated for drilling from CD2 and CD4. An
injector-producer pair, (CD2-73 & CD2-74), is to be drilled to the north of CD2-75 and CD2-59 in
2009. The drilling order and timing are a function of coordinating the drilling schedule with
several coincident drilling programs and summer rig move restrictions.
In 2009, CD1-48 (originally CD1-38 ext), a C sand producer was drilled early in the year. This
well is one of an injector/producer pair on the south flank of the CD1 area west of CD1-46. CD1-
39 South is the injector planned for CD1-48, but the drilling of the well depends on the outcome
of CD1-48 and rig availability and timing among other considerations. In the current plan CD1-
39S is not drilled until 2011 however this timing would most likely be accelerated given good
results at CD1-48.
Several other Alpine drilling prospects are being considered from CD1, CD2, and CD4. The
success of drilling CD4-05 and CD4-16 has indicated additional development potential for three
wells to the immediate south, as well as an injector to the west of CD4-05 (drilled from CD2).
Any number of these prospects could be drilled in 2009 depending on rig schedule and
availability. A sidetrack of CD2-60 to the west and parallel to CD4-16 at a closer location (than
its current 2000-foot spacing) is being evaluated as well. Additionally, approximately three to
seven CD1 locations are being evaluated in the Northeast periphery of the Alpine C Sand
reservoir. If these prospects prove to be economically viable, they will be drilled as rig
availability allows. See Attachment 2 to view coordinates of all wells drilled as of February 1,
2009.
Note that all of the 2009 wells mentioned above may be subject to deferral or removal from the
planned 2009 program. The rig portfolio is constantly under review and changes are regularly
made. These review changes may include the addition of wells not listed above.
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
7
5.5 Facilities Expansion Evaluation Results and Update
Prior to the summer of 2004, the combined well productivity from CD1 and CD2 regularly
exceeded the plant’s capacity. Various wells were choked from time to time to manage the oil
production rate. Major facility expansion was required to increase the oil rate. Concurrent with
expansion of the oil train, expansion of the seawater injection system was needed to support
higher offtake rates.
ACX Phase 1
The Alpine Capacity Expansion Project Phase 1 (ACX1) was approved by the Alpine working
interest owners in April 2003, and work was completed in the summer of 2004.
The ACX1 Project increased oil production rates by 5,000 BOPD (gross). The project increased
oil and gas processing capacity, and enabled re-injection of produced water into the Alpine
formation. ACX1 increased the produced water handling system from 10 MBWPD to 100
MBWPD, and gas processing capacity from 130 MMSCFD to 160 MMSCFD.
ACX Phase 2
The Alpine Capacity Expansion Project Phase 2 (ACX2) was approved by the Alpine working
interest owners in February 2004, and work was completed in the 2004 and 2005 summer shut
down periods. Building on ACX1, the ACX2 project consisted of adding or upgrading equipment
to increase the oil processing capacity to 140 MBOPD rate (at watercuts less than 1%), added
another 20 MMCFD of gas processing capacity (to 180 MMSCFD total), and expanded the
seawater injection capacity to 133 MBWPD (from 98 MBWPD).
The ACX2 project enhances the Alpine recovery process. The seawater injection system allows
higher throughput rates and increases cumulative water injection which results in increased
incremental recovery. ACX2 expansion of the gas handling system increases the volume of
miscible injectant available for the MWAG flood which results in a larger cumulative volume of
miscible injectant in the reservoir and therefore incrementally higher EOR recovery from the
MWAG process.
ACX Phase 3
In January 2005 the Alpine working interest owners approved the Alpine Capacity Expansion
Project Phase 3 (ACX3). The ACX3 project installed a stabilizer column, fired heater, reflux
drum, overhead condenser, reboiler, and a feed/bottoms exchanger at the Alpine Central
Facility. The primary purpose of the stabilizer and associated equipment is to optimize Alpine,
Fiord CD3, Nanuq CD4 and any future WNS enhanced oil recovery projects. In addition, the
stabilizer adds value and reserves by recovering and selling heavier condensate components
that would otherwise be re-injected into the reservoir as part of the MI. Construction work was
completed in December 2006 and the stabilizer was started up in late December 2006 with an
initial production of 3 MBOPD. The stabilizer has now been in operation for over a year and
continues to perform well.
Emergency Power Upgrade
Construction and tie-in has been completed to replace the original emergency power generators
at Alpine. In 2000, dual Cummins Wartsilla diesel generators were placed in service at Alpine to
provide emergency black start power. With plant power demands increasing in response to the
upgrades described above, it became necessary to replace the diesel units with higher capacity
turbine generator packages. On the 2004 ice road, dual solar turbines were shipped over to
Alpine. Construction commenced following the 2004 summer shutdown and turbines were
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
8
placed in service in February 2005. The original power packages were removed from service in
the spring of 2006.
Alpine Water Handling Project
The Alpine Water Handling Project (AWHP) seeks to increase both capacity and flexibility of the
water injection system at Alpine. As Alpine’s produced water (PW) forecast profile has changed
over time, PW volumes are projected to peak at a rate higher than originally anticipated. The
current infrastructure is not configured to handle the higher PW rates and maintain segregation
of PW and seawater (SW), which is recommended for long-term Asset and Operating Integrity.
This situation limits the ability to inject water where it is required for maximizing recovery of
reserves.
The scope of this project includes: two new 1200 hp water injection pumps, a variable frequency
drive module, piping modifications and tie-ins at the ACF, and a power distribution upgrade at
ACF. The pumps and piping at ACF are anticipated to startup in the third quarter of 2009.
Conclusion
Alpine reservoir performance remains strong. All Alpine wells planned for development of the
main field have been drilled and completed as of November 2005. Limited additional drilling
opportunities may be progressed in 2009; one candidate well has already drilled at time of
writing (CD1-48) with four (4) additional producers and three (3) additional injectors tentatively
scheduled for this year. The MWAG EOR project will continue throughout 2009 based on the
excellent response seen to date. We foresee no significant obstacles to continued successful
exploitation of the Alpine resource at this time.
1
2008 Annual Reservoir Review, Fiord, Nanuq, Nanuq-Kuparuk, and
Qannik Oil Pools
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
9
Nanuq Oil Pool
Conservation Order 562, Rule 10 requires this Annual Reservoir Review Report.
Overview of Reservoir Performance
Nanuq production averaged 528 BOPD with a gas-oil ratio of 1835 SCF/STB and a watercut of
18%. Injection volume in 2008 was negligible as service wells were used to monitor pressure in
2008.
Future Development and Reservoir Depletion Plans
No development drilling is planned in 2009. Water injection is planned for 2009.
Surveillance Information
a. Reservoir Pressure Map at Datum:
See Attachment 9, Nanuq and Nanuq-Kuparuk Reservoir Pressure Map at Datum.
b. Summary and Analysis of Reservoir Pressure Surveys:
See Attachment 10, Nanuq Form 10-412 Reservoir Pressure Report.
c. Estimate of Reservoir Pressure
The average Nanuq Oil Pool reservoir pressure was estimated to be 2647 psi.
d. Results of Special Surveys
Interwell communication was demonstrated with pressure monitoring of two service wells while
producing three oil development wells.
e. Estimate of yearly production and reservoir voidage balance:
See Attachment 11.
f. Progress of Plans and Tests to Expand the Productive Limits of the Pool
Nanuq interval logs were collected in a well completed in the Kuparuk interval (CD4-301 and
CD4-301A) and incorporated into the reservoir description.
g. Results of Safety Valve System Testing:
See Attachment 12, Results of Safety Valve System Testing
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
10
Nanuq-Kuparuk Oil Pool
Conservation Order 563, Rule 10 requires this Annual Reservoir Review Report.
Overview of Reservoir Performance
Nanuq-Kuparuk production averaged 21,444 BOPD with a gas-oil ratio of 741 SCF/STB and a
watercut of 0.07%. Water production attributable to injection was detected near 2008 year end.
Injection/withdrawal ratio (I/W) calculation is reported as 0.8. However, an injection metering
error was discovered and corrected in Nov-2008, but retroactive reallocation of injection
volumes to the service wells has not yet been completed. The retroactive meter correction will
increase the amount of enriched gas allocated to Nanuq-Kuparuk service wells, and will
increase I/W. Production performance, pressure measurements, and preliminary estimates of
corrected meter volumes suggests an I/W of slightly greater than 1.0.
Future Development and Reservoir Depletion Plans
Continuation of enriched gas injection alternating with waterflood is planned. Five bottomhole
locations are planned for future drilling; one well (CD4-303) is planned for 2009.
Surveillance Information
a. Reservoir Pressure Map at Datum:
See Attachment 9, Nanuq and Nanuq-Kuparuk Reservoir Pressure Map at Datum.
b. Summary and Analysis of Reservoir Pressure Surveys:
See Attachment 13, Nanuq-Kuparuk Form 10-412 Reservoir Pressure Report.
c. Estimate of Reservoir Pressure
The average Nanuq-Kuparuk pressure measured in the Drillsite CD4 area was 3302 psi. The
pressure measured in CD1-17 Kuparuk interval was 4691 psi. Gas injection in the CD1 area is
the likely cause of the localized, higher pressure in CD1-17.
d. Results of Special Surveys
No special surveys were completed in 2008.
e. Estimate of yearly production and reservoir voidage balance:
See Attachment 14.
f. Progress of Plans and Tests to Expand the Productive Limits of the Pool
Prospective bottomhole locations planned for future drilling are outside of the known productive
limits of the Drillsite CD4 area.
g. Results of Safety Valve System Testing:
See Attachment 12, Results of Safety Valve System Testing
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
11
Fiord Oil Pool
Conservation Order 569, Rule 9 requires this Annual Reservoir Review Report.
Overview of Reservoir Performance
Production from the Fiord Oil Pool had an average rate of 18,269 BOPD at solution gas-oil ratio.
The Nechelik interval produced essentially no water, and water production continued from the
Kuparuk interval.
Future Development and Reservoir Depletion Plans
Development plans for 2009 include drilling the two Nechelik wells (CD3-115 and CD3-117), two
Kuparuk wells (CD3-304 and CD3-305) in 2009. Conversion of well CD3-118, and hydraulic
fracturing of CD3-107 are planned for 2009. Continuation of enriched gas alternating with
waterflood is also planned for 2009.
Surveillance Information
a. Reservoir Pressure Map at Datum:
See Attachment 15, Fiord Reservoir Pressure Map at Datum.
b. Summary and Analysis of Reservoir Pressure Surveys:
See Attachment 16, Fiord Form 10-412 Reservoir Pressure Report.
c. Estimate of Reservoir Pressure
The estimate of the Fiord Oil Pool pore volume-weighted average reservoir pressure is 3268 psi
at 6850’ SSTVD.
d. Results of Special Surveys
Pressure responses in the Kuparuk interval suggested anisotropic permeability.
e. Estimate of yearly production and reservoir voidage balance:
See Attachment 17.
f. Progress of Plans and Tests to Expand the Productive Limits of the Pool
Drill and log four development wells planned during the 2009 ice road season. Evaluate open
hole fracturing of the Nechelik producers.
g. Results of Safety Valve System Testing:
See Attachment 12, Results of Safety Valve System Testing
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
12
Qannik Oil Pool
Conservation Order 605, Rule 9 requires this Annual Reservoir Review Report.
Future Development and Reservoir Depletion Plans
There are no development plans for Qannik in 2009. Continuation of waterflood is planned.
Surveillance Information
1. Qannik Monthly Injection and Production Values for 2008:
Qannik Injection and Production for 2008
Injected fluids
(bbls)
Produced Fluids
(bbls)
Voidage Balance
(I/W)
January 0 0 1
February 0 0 1
March 0 0 1
April 0 0 1
May 0 0 1
June 0 0 1
July 0 97642 0
August 0 51225 0
September 32298 51003 0.63
October 120376 79252 1.52
November 119319 123582 0.97
December 186589 161173 1.16
Total 458582 563876 0.81
2. Reservoir Pressure Map at Datum and Summary and Analysis of Reservoir
Pressure:
See Attachment 18, Qannik Reservoir Pressure Map at Datum and Attachment 19 for Qannik
Form 10-412 Reservoir Pressure Report.
3. Results of Qannik Production/Injection logs:
• 9/14/2008 - CD2-467 - Perform RST water flow log to demonstrate zonal
isolation - PASSED, No up flow detected
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
13
4. Qannik Pool Production Allocation Factors:
Gas Allocation
Factor
Water Allocation
Factor
Oil Allocation
Factor
1/31/2008 1.0021 0.9614 0.9617
2/29/2008 1.0434 0.8859 0.9620
3/31/2008 0.9939 0.8584 0.9712
4/30/2008 1.0481 0.9228 0.9473
5/31/2008 1.0623 0.9954 0.9666
6/30/2008 1.0595 0.9752 0.9473
7/31/2008 1.0595 0.9678 0.9485
8/31/2008 1.0270 0.5761 0.5745
9/30/2008 1.0444 0.8909 0.9627
10/31/2008 1.0537 0.9483 0.9602
11/30/2008 1.0796 0.9692 0.9561
12/31/2008 1.1426 1.0034 0.9678
5. Progress of Enhanced Recovery Project:
Water injection into the Qannik reservoir began in the third quarter of 2008. No water break
through has been observed in the Qannik. There is no MI or lean gas injection at Qannik.
6. Reservoir Management Summary:
The current well count for the Qannik CD2 development is 9 wells (3 Injectors, 6 Producers).
There are no development plans for Qannik in 2009.
• 2008 oil production .......................................................254,698 STB
• 2008 gas production .....................................................337,037 MSCF
• 2008 water production ..................................................531 Bbls
• 2008 Cumulative seawater injection.............................458,582 Bbls
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
14
Attachment 1: CRU Boundary effective as of August 15, 2005
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
15
Attachment 2: All Wells Drilled as of January 1, 2009
Surface Well Information
Well Well Start of Completion End of Completion
Name Service
7" Csg
Shoe X start Y start TD X end Y end
CD1-01 Injector 7752 386226 5977656 10289 384975 5979854
CD1-02 Injector 8201 388914 5978054 12773 386773 5982084
CD1-03 Injector 7816 387016 5975903 10897 388337 5973122
CD1-04 Producer 9444 390285 5979213 13977 392388 5975199
CD1-05 Injector 10633 392065 5979111 14515 393810 5975646
CD1-06 Injector 13500 395921 5978194 16024 397043 5975933
CD1-07 Injector 13477 395838 5971680 17542 397737 5968095
CD1-08 Producer 12515 394559 5970944 15837 396092 5967999
CD1-09 Producer 11894 393604 5979402 15350 395153 5976315
CD1-10 Producer 7909 387919 5977328 11693 389639 5973962
CD1-11 Injector 12293 393432 5969790 15057 394737 5967356
CD1-12 Producer 11656 392008 5969456 12912 392582 5968340
CD1-13 Injector 8841 389949 5976723 11300 391036 5974524
CD1-14 Injector 14073 397423 5974752 18939 399752 5970483
CD1-16 Injector 9595 391456 5973711 12600 392819 5971035
CD1-17 Producer 13181 395639 5975431 18590 398233 5970693
CD1-18 Producer 11382 389206 5968235 15056 390928 5964996
CD1-20 Injector 10634 389768 5969450 16114 392499 5964709
CD1-21 Injector 9049 381896 5979206 11087 380972 5981020
CD1-22 Producer 8430 387229 5978470 9236 386794 5979148
CD1-23 Injector 11473 394161 5974990 14477 395504 5972306
CD1-24 Producer 10771 392946 5974121 13706 394333 5971538
CD1-25 Producer 8887 390067 5973033 12147 391614 5970167
CD1-26 Injector 8554 388729 5972343 11134 389929 5970059
CD1-27 Producer 8500 387434 5971694 11492 388770 5969018
CD1-28 Producer 7449 385822 5974801 10468 387229 5972131
CD1-30 Producer 9520 380597 5978488 12850 379073 5981447
CD1-31 Injector 10388 379306 5977679 14364 377530 5981235
CD1-32 Producer 11128 378022 5977019 14353 376466 5979841
CD1-33 Injector 7878 384485 5974129 10854 385846 5971484
CD1-34 Producer 8410 383109 5973412 11190 384448 5970977
CD1-35 Producer 8158 384636 5977159 13450 382165 5981835
CD1-36 Injector 7654 383597 5975923 10654 382248 5978601
CD1-37 Injector 9095 386283 5970682 12134 387689 5967992
CD1-38 Producer 9170 384724 5970395 12240 386139 5967673
CD1-39 Injector 10288 383468 5969466 13298 384825 5966783
CD1-40 Producer 12042 382637 5967963 15438 384188 5964948
CD1-41 Producer 8333 382239 5975220 11170 380948 5977745
CD1-42 Injector 9054 380961 5974612 11608 379729 5976849
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
16
Surface Well Information
Well Well Start of Completion End of Completion
Name Service
7" Csg
Shoe X start Y start TD X end Y end
CD1-43 Producer 10065 380436 5972089 12921 381823 5969594
CD1-44 Producer 10070 379572 5973840 12811 378333 5976283
CD1-45 Injector 9032 381802 5972762 11950 383139 5970169
CD1-46 Injector 11334 387838 5967599 15187 389598 5964174
CD2-01 Producer 12953 378098 5982112 17513 376080 5986195
CD2-02 Injector 16048 359979 5982023 21178 357334 5986377
CD2-03 Producer 13774 367095 5984985 15682 366191 5986658
CD2-05 Producer 13712 363517 5970008 17816 361616 5973641
CD2-06 Injector 9672 371098 5980645 16680 367816 5986833
CD2-07 Injector 10857 373650 5982084 14977 371786 5985755
CD2-08 Injector 12242 377278 5981611 18050 374565 5986743
CD2-09 Producer 12617 365177 5982158 16094 363562 5985233
CD2-10 Producer 10702 372139 5982079 14475 370284 5985362
CD2-11 Injector 13809 363590 5981961 18187 361600 5985857
CD2-12 Injector 8677 368888 5978304 13632 366637 5982712
CD2-13 Producer 10595 376177 5980472 14575 374339 5983995
CD2-14 Producer 7671 371963 5975571 11056 370410 5978577
CD2-15 Injector 9830 366147 5977039 14161 364157 5980881
CD2-16 Injector 9529 375990 5977319 12500 374782 5980013
CD2-17 Injector 8184 373143 5976621 8756 372880 5977129
CD2-17A Injector 8184 373143 5976621 11819 371497 5979862
CD2-18 Injector 12112 362855 5975882 18019 360209 5981156
CD2-19 Producer 8769 375572 5975101 11714 376896 5972473
CD2-20 Producer 9163 369916 5979552 14570 367451 5984361
CD2-21 Producer 13382 371703 5974582 19359 360057 5985547
CD2-22 Injector 7845 370575 5975090 11134 369051 5978002
CD2-23 Producer 9676 367151 5978350 13438 365445 5981699
CD2-24 Producer 10811 364768 5976380 14301 363212 5979501
CD2-25 Producer 8722 369286 5974237 11994 367790 5977144
CD2-26 Injector 8619 374207 5974408 11238 375406 5972081
CD2-27 Injector 12461 377930 5967068 18250 380637 5961965
CD2-28 Producer 8695 374897 5976522 13200 372799 5980502
CD2-29 Injector 9556 376873 5975841 12560 378234 5973167
CD2-30 Injector 11481 365217 5971303 15700 363306 5975062
CD2-31 Producer 13598 361069 5974966 18131 358947 5978966
CD2-32 Injector 8723 367954 5973557 11720 366579 5976218
CD2-33B Producer 9982 366697 5972759 13078 365223 5975475
CD2-34 Producer 7802 372917 5973731 8755 373367 5972891
CD2-35A Injector 9063 375633 5971746 13500 377673 5967818
CD2-36 Injector 13523 372731 5964073 17663 374634 5960399
CD2-37 Producer 14162 371725 5963095 17085 373038 5960491
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009
Reservoir Review Reports, Colville River Field
17
Surface Well Information
Well Well Start of Completion End of Completion
Name Service
7" Csg
Shoe X start Y start TD X end Y end
CD2-38 Injector 9209 373424 5969394 13010 375164 5966020
CD2-39 Producer 9122 374692 5970192 12651 376369 5967087
CD2-40 Injector 11208 365775 5970211 14250 367117 5967484
CD2-41 Producer 9532 372019 5968832 13024 373637 5965742
CD2-42 Producer 9633 367542 5970978 13138 369171 5967884
CD2-43 Producer 13106 364417 5968231 19040 367196 5962998
CD2-44 Injector 11319 378889 5972087 14555 380338 5969198
CD2-45 Producer 9972 377360 5971508 13402 378989 5968491
CD2-46 Injector 7879 371539 5973093 11000 372970 5970320
CD2-47 Producer 10840 369515 5967325 14580 371256 5964017
CD2-48 Injector 10074 370711 5968227 13622 372304 5965058
CD2-49 Injector 8890 368809 5971733 11874 370200 5969094
CD2-50 Producer 7909 370191 5972556 11624 371794 5969207
CD2-51 Injector 13246 380577 5968583 17320 382471 5964985
CD2-52 Producer 12897 379292 5967820 16881 381127 5964289
CD2-53 Producer 12394 376772 5966066 16985 378960 5962036
CD2-54 Injector 14378 361169 5970560 18250 359460 5974033
CD2-55 Injector 12210 367573 5966569 15238 368976 5963888
CD2-56 Injector 14391 362859 5967271 19554 365279 5962714
CD2-57 Injector 12642 375598 5965124 16433 377321 5961749
CD2-58 Producer 12129 373883 5965245 16389 375838 5961468
CD2-59 Injector 15743 358798 5974508 20027 357078 5978426
CD2-60 Injector 14331 369427 5962859 18695 371542 5959079
CD2-72 Producer 16693 358480 5980386 21089 356322 5984105
CD2-75 Producer 15702 359176 5970328 23539 355431 5977153
CD4-05 Producer 15140 366426 5956030 21142 363633 5961338
CD4-07 Producer 17716 363602 5962039 25040 360029 5968372
CD4-16 Producer 11664 369790 5957923 16850 367402 5962514
CD4-17 Injector 13334 368008 5957262 17975 365933 5961403
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 18Attachment 3: MWAG conversion status at CD1
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 19Attachment 4: MWAG maturity CD1
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 20Attachment 5: MWAG conversion status at CD2
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 21Attachment 6: MWAG maturity at CD2
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 22Attachment 7: Recovery - throughput response at Alpine 01020304050607080901000.00.10.20.30.40.50.60.70.80.91.0Injected Volume (fraction HCPV)Oil Recovery (%OOIP)TPMWater BTGas BTCD1CD2
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 23Attachment 8: Alpine Form 10-412 Reservoir Pressure Report 6. Oil Gravity:408. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD1-02 501032035400 WAG 120100 C 6849-6816 11/3/08 1282 SBHP 120 6849 4236 7000 .109 4252CD1-04 501032034600 O 120100C6825-6841 4/13/08 6284 SBHP 158 6825 4572 7000 .33 4630CD1-04 501032034600 O 120100C6825-6841 7/2/08 10607 SBHP 155 6825 4611 7000 .3 4664CD1-09 501032033900 O 120100 C 6810-6842 4/14/08 7685 SBHP 159 6810 4761 7000 .33 4824CD1-10 501032035300 O 120100 C 6884-6911 3/6/08 4793 SBHP 159 6884 3944 7000 .3 3979CD1-13 501032030000 WAG 120100 C 6886-6873 11/2/08 1211 SBHP 140 6886 4388 7000 .136 4404CD1-14 501032037100 WAG 120100 C 6799-6757 8/8/08 4.7 SBHP 141 6799 4668 7000 .118 4692CD1-17 501032035000 O 120100C6825-6813 4/27/08 3842 SBHP 154 6825 4831 7000 .298 4883CD1-20 501032050300 WAG 120100 C 6952-7004 4/14/08 123 SBHP 122 6952 3601 7000 .33 3617CD1-22A 501032025001 O 120100 C 6875-6869 7/5/08 1856 SBHP 155 6875 4385 7000 .171 4406CD1-27 501032032400 O 120100 C 7007-6993 3/8/08 81 SBHP 151 7007 1937 7000 .442 1934CD1-28 501032035600 O 120100 C 6965-7005 2/21/08 120 SBHP 151 6965 2,745 7000 .442 2760CD1-28 501032035600 O 120100 C 6965-7005 8/20/08 243 SBHP 153 6965 2,128 7000 .33 2139CD1-30 501032034800 O 120100 C 7017-6991 3/11/08 2411 SBHP 159 7017 3,412 7000 .44 3405CD1-32 501032030800 O 120100 C 7082-7100 7/8/08 375 SBHP 159 7081 2,482 7000 .086 2475CD1-34 501032033300 O 120100 C 7050-7031 3/3/08 71 SBHP 153 7050 2,400 7000 .442 2398CD1-35 501032029700 O 120100 C 6998-6955 2/25/08 39 SBHP 158 6998 2,401 7000 .4 2402CD1-39 501032030400 WAG 120100 C 7070-7053 4/12/08 69.8 SBHP 120 7070 4,770 7000 .33 4747CD1-40 501032029800 O 120100 C 7102-7129 3/28/08 112 SBHP 158 7102 1,322 7000 .447 1276CD1-40 501032029800 O 120100 C 7102-7129 4/2/08 234,5 SBHP 155 7102 1,692 7000 .447 1646CD1-40 501032029800 O 120100 C 7102-7129 4/18/08 622.3 SBHP 157 7102 1,050 7000 .154 1034ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River/Alpine Oil Pool 7000' SS .783. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Tim Schneider23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction Engineer
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 24Attachment 8 (continued): Alpine Form 10-412 Reservoir Pressure Report 6. Oil Gravity:408. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD1-44 501032033500 O 120100 C 7060-7058 3/12/08 79.9 SBHP 149 7060 1,412 7000 .447 1385CD2-02 501032051300 WAG 120100 C 7207-7189 3/8/08 277.8 SBHP 132 7207 4403 7000 .298 4341CD2-24 501032037700 O 120100 C 7179-7150 8/20/08 268 SBHP 160 7179 1,722 7000 .315 1666CD2-25 501032041800 O 120100 C 7158-7108 8/21/08 292SBHP160 7158 956 7000 .024 952CD2-28 501032043500 O 120100 C 7114-7111 8/13/08 100 SBHP 160 7114 1,653 7000 .307 1618CD2-39 501032038700 O 120100 C 7227-7228 1/30/08 97 SBHP 158 7175 2,305 7000 .442 2228CD2-41 501032042400 O 120100 C 7145-7167 2/12/08 168 SBHP 151 7145 2,236 7000 .442 2172CD2-42 501032037400 O 120100 C 7221-7345 10/23/08 695 SBHP 146 7221 2,493 7000 .402 2404CD2-45 501032039500 O 120100 C 7114-7085 8/12/08 80 SBHP 158 7114 1,301 7000 .218 1276CD2-50 501032041500 O 120100 C 7142-7190 8/20/08 267 PBU 158 7142 1,089 7000 .037 1084CD2-57 501032049200 WAG 120100 C 7195-7243 6/5/08 47 SBHP 125 7195 3,866 7000 .446 3779CD2-72 501032054600 O 120100 A 7225-7199 3/12/08 168 SBHP 156 7214 2,317 7000 .3 2253CD2-75 501032057300 O 120100 A 6811-7314 5/27/08 96 SBHP 160 7332 3,987 7000 .298 3888CD4-05 501032055800 O 120100 A7383-7388, 7502-7435 4/23/08 77.5 SBHP 157 7497 2,119 7000 .447 1897CD4-05 501032055800 O 120100 C7383-7388, 7502-7435 4/28/08 0 SBHP 153 7497 3,798 7000 .447 3576CD4-05 501032055800 O 120100 C7383-7388, 7502-7435 8/16/08 174 SBHP 170 7497 2,972 7000 .167 2889CD4-05 501032055800 O 120100 A7383-7388, 7502-7435 8/16/08 181.9 PBU 172 7497 2,307 7000 .298 2159CD4-16 501032053500 O 120100 A7386-7359 4/17/08 211 SBHP 158 7405 2,014 7000 .447 1833Tim Schneider23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction EngineerSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River/Alpine Oil Pool 7000' SS .783. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 25Attachment 8 (continued): Alpine – Kuparuk Undefined Oil Pool Form 10-412 Reservoir Pressure Report 6. Oil Gravity:408. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD1-04 501032034600 O UndefinedKuparuk/Undefined Pool6709-6717 8/5/08 236 SBHP 156 6825 4553 7000 .342 4613CD1-04 501032034600 O UndefinedKuparuk/Undefined Pool6709-6717 10/16/08 1154 SBHP 153 6825 4305 7000 .45 4384ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River/Kuparuk/Undefined Oil Pool 7000' SS 0.783. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:STATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:Tim Schneider23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction Engineer
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 26Attachment 9: Nanuq and Nanuq-Kuparuk Reservoir Pressure Map at Datum
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 27Attachment 10: Nanuq Form 10-412 Reservoir Pressure Report 6. Oil Gravity:408. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD4-209 501032053200 O 120175Nanuq6145-6142 11/7/08 15480 SBHP 132 6041 2633 6150 0.062 2665CD4-210 501032053300 O 120175 Nanuq6180-6191, 6189-6182, 8/13/08 1989 SBHP 134 6178 2659 6150 .177 2654CD4-214 501032053700 WI 120175 Nanuq 6153-6204 1/1/08 9999 SBHP 128 5937 2576 6150 2639CD4-214 501032053700 WI 120175 Nanuq 6153-6204 2/1/08 9999 SBHP 128 5937 2572 6150 2635CD4-214 501032053700 WI 120175 Nanuq 6153-6204 3/1/08 9999 SBHP 128 5937 2569 6150 2632CD4-214 501032053700 WI 120175 Nanuq 6153-6204 4/1/08 9999 SBHP 128 5937 2565 6150 2628CD4-214 501032053700 WI 120175 Nanuq 6153-6204 11/7/08 5125 SBHP 131 6005 2555 6150 0.292 2598CD4-209 501032053200 O 120175Nanuq6145-6142 3/1/08 9456 SBHP 131 5997 2620 6150 2665CD4-209 501032053200 O 120175Nanuq6145-6142 4/1/08 10200 SBHP 131 5997 2618 6150 2663CD4-209 501032053200 O 120175Nanuq6145-6142 5/1/08 10920 SBHP 131 5997 2615 6150 2660CD4-209 501032053200 O 120175Nanuq6145-6142 6/1/08 11664 SBHP 131 5997 2613 6150 2658CD4-209 501032053200 O 120175Nanuq6145-6142 7/1/08 12384 SBHP 131 5997 2610 6150 2655CD4-209 501032053200 O 120175Nanuq6145-6142 8/1/08 13128 SBHP 131 5997 2608 6150 2653Jack Walker23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateReservoir EngineerSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River, Nanuq-Nanuq Oil Pool 6150' SS .853. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 28Attachment 11: Nanuq Estimate of Yearly Production and Reservoir Voidage Balance Oil (STBO) Gas (MSCF) Water (STB)FGOR (SCF/STB)Withdrawal (RB) Water (STB) Gas (MSCF)Total Injection (RB) (RB/RB)2006 4,788 6,245 1 1304 8614 19,097 0 19097 2.222007 156,454 345,360 28,075 2207 432739 85,584 0 85584 0.202008 193,403 354,827 43,813 1835 481178 7,065 0 7065 0.01Annual InjectionAnnual Production Injection/Withdrawal
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 29Attachment 12: Results of Safety Valve System Testing, CD2 Date: 9/11/2008LPS 150 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD2-404 2060540 9/14/2008 WAGCD2-463 2081700 150 100100 P P P 9/5/2008 OILCD2-464 2082820 150 100 100 P P P OILCD2-467 2081140 WAGWells:39 117Failure32.56%Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Mike MishlerField/Unit/Pad: Alpine/ CRU / CD2Remarks:Bob Noble was contacted on 9/04/08 and told us to proceed with testing without himAOGCC Rep: Waived Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 30Attachment 12 (continued): Results of Safety Valve System Testing, CD3 Date: 4/21/2008LPS 147 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD3-107 2061890 4/8/2008 SICD3-108 2050330 WAGCD3-109 2050590 147 100 100 P P P OILCD3-110 2050410 WAGCD3-112 2060320 WAGCD3-113 2070040 147 100 100 P P P OILCD3-114 2070330 WAGCD3-301 2070230 147 100 100 P P P OILCD3-302 2060100 WAGWells:39Failures00.00%Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Pat MizeField/Unit/Pad: Alpine / CRU / CD3Remarks:AOGCC Rep: Bob Noble Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 31Attachment 12 (continued): Results of Safety Valve System Testing, CD3 Date: 4/23/2008LPS 149 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD3-111 2060300 149 100 100 P P 9 OILCD3-118 2080250 149 100 100 P P P OILCD3-316A 2080110 149 100 95 P P P OILWells:39Failures1Oil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:Remarks:CD3-111 is scheduled for wire line to repair SSSV.AOGCC Rep: Waived Separator psi:Well Data PilotsOperator Rep: Pat MizeField/Unit/Pad: Alpine / CRU / CD3Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich Ligenza90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 32Attachment 12 (continued): Results of Safety Valve System Testing, CD3 ConocoPhillipDate: 10/4/2008LPS 150 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD3-107 2061890 150 100 100 P P P OILCD3-108 2050330 WAGCD3-109 2050590 150 100 103 P P P WAGCD3-110 2050410 WAGCD3-111 2060300 150 100 94 P P 8 OILCD3-112 2060320 WAGCD3-113 2070040 150 100 96 P P P OILCD3-114 2070330 WAGCD3-118 2080250 150 100 98 P P 8 OILCD3-301 2070230 6/3/2008 SICD3-302 2060100 5/15/2008 SICD3-303 2080130 150 100 103 P P P OILCD3-316A 2080110 WAGWells:618Failures211.11%Oil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:Remarks:CD3-118 and CD3-111 SSSV's have been scheduled for service.AOGCC Rep: J. Crisp Separator psi:Well Data PilotsOperator Rep: R. AlexanderField/Unit/Pad: Alpine / CRU / CD3Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: Submitted By: R.Alexander90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 33Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 4/18/2008LPS 140 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-208 2051620 4/5/2008 WAGCD4-209 2060650 WAGCD4-210 2060770 4/24/2008 SICD4-214 2061450 WAGCD4-302 2070560 WAGCD4-306 2070940 1850 1850 P P P GINJCD4-318A 2061130 140 100 102 P P P OILCD4-320 2060550 140 100 102 P P P OILCD4-321 2061420 WAGWells:515Failures00.00%Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Rodney FrencField/Unit/Pad: Alpine / CRU/ CD4Remarks:AOGCC Rep: John Crisp Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 34Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 4/19/2008LPS 139 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-304 2071320 139 100 98 P P P OILCD4-319 2051480 1850 1850 P P P GINJWells:26Failures0Oil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:Remarks:AOGCC Rep: Waived Separator psi:Well Data PilotsOperator Rep: Rodney FrencField/Unit/Pad: Alpine / CRU/ CD4Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich Ligenza90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 35Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 4/20/2008LPS 140 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-322 2071010 1850 1850 P P 9 04/22/08 GINJWells:13Failures1Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Rodney FrencField/Unit/Pad: Alpine / CRU/ CD4Remarks:CD4-322 SSSV was serviced and passed retest on 04/22/08AOGCC Rep: Waived Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 36Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 4/24/2008LPS 140 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-210 2060770 04/24/08 SICD4-211 2061530 140 100 101 P P P OILWells:13Failures0Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Rodney FrencField/Unit/Pad: Alpine / CRU/ CD4Remarks:AOGCC Rep: Waived Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 37Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 4/25/2008LPS 141 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-215 2061570 141 100 100 P P P OILWells:13Failures0Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: Rich LigenzaOperator Rep: Rodney FrencField/Unit/Pad: Alpine / CRU/ CD4Remarks:AOGCC Rep: Waived Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 38Attachment 12 (continued): Results of Safety Valve System Testing, CD4 Date: 10/03/08LPS 150 HPSSSVSSSVRetest/SI Date Well TypeWell Permit Separ Set L/P Test Test Test Date Passed RetestNumber Number PSI PSI Trip Code Code Code Or Date Shut InCD4-209 2060650 04/24/07 SICD4-210 2060770 05/22/08 SICD4-211 2061530 150 100 97 P P P OILCD4-214 2061450 04/07/08 SICD4-215 2061570 10/03/08 SICD4-301B 2071800 150 100 103 P P P OILCD4-302 2070560 1850 1845 P P P GINJCD4-304 2071320 150 100 101 P P P OILCD4-318A 2061130 150 100 98 P P P OILCD4-319 2051480 WAGCD4-320 2060550 150 100 100 P P P OILCD4-321 2061420 1850 1850 P 4 P 10/04/08 GINJCD4-322 2071010 WAGWells:11 33Failures13.03%Alaska Oil and Gas Conservation CommissionSafety Valve System Test ReportOperator: ConocoPhillipSubmitted By: R.AlexanderOperator Rep: R.AlexanderField/Unit/Pad: Alpine / CRU / CD4Remarks: CD4-321 SSV was serviced and passed retest on 10/04/08 AOGCC Rep: J.Crisp Separator psi:Well Data PilotsOil, WAG, GINJ, GAS, CYCLE, SIComponents: Failure Rate:90 Day 90 Day 90 Day 90 Day 90 Day
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 39Attachment 13: Nanuq-Kuparuk Form 10-412 Reservoir Pressure Report 6. Oil Gravity:408. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD1-17 501032035000 O 120185Nanuq Kuparuk6675-6683 6/9/08 1754 SBHP 156 6825 4633 7000 .33 4691CD4-301B 501032055702 O 120185Nanuq Kuparuk6859-6865, 6862-68594/29/08 0 SBHP 142 6855 3200 7000 .33 3248CD4-302 501032054500 WAG 120185Nanuq Kuparuk6883-6894 1/16/08 573 SBHP 100 6889 3051 7000 .3 3084CD4-302 501032054500 WAG 120185Nanuq Kuparuk6883-6894 3/30/08 317 SBHP 102 6889 3108 7000 .33 3145CD4-321 501032054500 WAG 120185Nanuq Kuparuk7244-7256 8/28/08 449 SBHP 160 7097 3760 7000 0.3 3731 Jack Walker23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction EngineerSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:ConocoPhillips Alaska Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River, Nanuq-Kuparuk Pool 7000 .853. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 40Attachment 14: Nanuq-Kuparuk Estimate of Yearly Production and Reservoir Voidage Balance Oil (STBO) Gas (MSCF) Water (STB)FGOR (SCF/STB)Withdrawal (RB) Water (STB) Gas (MSCF)Total Injection (RB) (RB/RB)2006 664,517 459,351 0 691 956,904 391,209 0 391,209 0.412007 6,078,919 4,358,159 1,312717 8,754,955 6,705,452 1,686,286 7,975,225 0.912008 7,848,597 5,817,738 5,188741 11,445,569 5,183,778 5,289,601 9,166,848 0.80Injection/WithdrawalAnnual InjectionAnnual Production
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 41Attachment 15: Fiord Reservoir Pressure Map at Datum
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 42Attachment 16: Fiord Form 10-412 Reservoir Pressure Report 6. Oil Gravity:298. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD3-107L1 501032052960 O 120120 FiordNech 6995-6939 8/18/08 192 SBHP 177 7026 2625 6850 .29 2574CD3-113 501032054100 O 120120 FiordNech 6876-6816 3/1/08 0 SBHP 160 6860 3285 6850 .47 3280CD3-113 501032054100 O 120120 Nechelik 6876-6816 8/23/08 326 PBU 160 6618 3267 6850 .327 3263CD3-114 501032054400 WI 120120 FiordNech 6877-6834 1/17/08 239 SBHP 158 6877 2575 6850 .33 2566CD3-118 501032057000 O 120120 FiordNech 6774-6779 4/3/08 0 SBHP 158 6893 2894 6850 .33 2880CD3-118 501032057000 O 120120 Fiord/Kup 6774-6779 5/11/08 0 SBHP 157 6776 3181 6850 .33 3205CD3-118 501032057000 O 120120 FiordNech 6774-6779 8/17/08 168 SBHP 154 6893 2684 6850 .33 2670CD3-118 501032057000 O 120120 FiordKup 6774-6779 8/22/08 284 SBHP 156 6776 2889 6850 .33 2913CD3-303 501032056800 O 120120 FiordKup 6624-6639 4/21/08 0 SBHP 166 6761 2637 6850 .33 2666CD3-316A 501032055901 O 120120 FiordKup6677-66662/15/08 0 SBHP 153 6677 2815 6850 .33 2872CD3-316A 501032055901 O 120120 FiordKup6677-66662/15/08 0 SBHP 128 6402 2855 6850 0.44 3052Jack Walker23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction EngineerSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River / Fiord Oil Pool 6850' SS .93. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 43Attachment 17: Fiord Estimate of Yearly Production and Reservoir Voidage Balance Oil (STBO) Gas (MSCF) Water (STB)FGOR (SCF/STB)Withdrawal (RB) Water (STB) Gas (MSCF)Total Injection (RB) (RB/RB)2006 1,780,380 1,111,585 5,790 624 2,342,971 866,290 0 866,290 0.372007 5,564,435 3,419,043 588,580 614 7,847,496 7,405,824 1,149,128 8,271,117 1.052008 6,686,495 4,301,216 324,985 643 9,207,615 8,352,054 1,774,995 9,688,625 1.05Injection/WithdrawalInjectionProduction
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 44Attachment 18: Qannik Reservoir Pressure Map at Datum
RE: 2008 Annual Reservoir Surveillance Report and April 1, 2009 Reservoir Review Reports, Colville River Field 45Attachment 19: Qannik Form 10-412 Reservoir Pressure Report 6. Oil Gravity:298. Well Name and Number:9. API Number 50XXXXXXXXXXXX NO DASHES10. Type See Instructions11. AOGCC Pool Code12. Zone 13. Perforated Intervals Top - Bottom TVDSS14. Final Test Date15. Shut-In Time, Hours16. Press. Surv. Type (see instructions for codes)17. B.H. Temp.18. Depth Tool TVDSS19. Final Observed Pressure at Tool Depth20. Datum TVDSS (input)21. Pressure Gradient, psi/ft.22. Pressure at Datum (cal)CD2-404501032053000WI 120180 Qannik 4012-4022 8/31/08 13865 SBHP 85 4019 1819 4000 .354 1812CD2-404501032053000WI 120180 Qannik 4012-4022 9/16/08 72 SBHP 83 4019 2107 4000 .441 2099CD2-404501032053000WI 120180 Qannik 4012-4022 10/2/08 456 SBHP 84 4019 1919 4000 .439 1911CD2-463501032057700O 120180 Qannik 4024-4028 7/20/08 0 SBHP 93 4023 1846 4000 .388 1837CD2-463501032057700O 120180 Qannik 4024-4028 8/14/08 128 SBHP 90 4023 1454 4000 .189 1450CD2-463501032057700O 120180 Qannik 4024-4028 9/13/08 241 SBHP 89 4023 1543 4000 .313 1536CD2-463501032057700O 120180 Qannik 4024-4028 10/5/08 769 SBHP 90 4023 1664 4000 .336 1656CD2-463501032057700O 120180 Qannik 4024-4028 10/28/08 1324 SBHP 90 4023 1706 4000 .34 1698CD2-464501032057400O 120180 Qannik 4044-4037 6/20/08 0 SBHP 90 4031 1888 4000 .34 1878CD2-464501032057400O 120180 Qannik 4044-4037 8/15/08 141 SBHP 88 4031 1261 4000 .546 1244CD2-465501032058300O 120180 Qannik 4020-4029 11/17/08 0 SBHP 92 4019 1847 4000 .388 1840CD2-466501032057600WI 120180 Qannik 4020-3979 10/6/08 0 SBHP 89 4021 1871 4000 .37 1863CD2-467501032057900WI 120180 Qannik 4025-4039 8/14/08 0 SBHP 92 4024 1869 4000 .54 1856CD2-470501032058100O 120180 Qannik 4043-4044 9/18/08 0 SBHP 85 4036 1868 4000 .359 1855Scott Reed23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.I hereby certify that the foregoing is true and correct to the best of my knowledge.SignaturePrinted NameTitleDateProduction EngineerSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSIONRESERVOIR PRESSURE REPORT1. Operator:2. Address:ConocoPhillips Alaska, Inc.P.O. Box 100360, Anchorage, AK 99510-03607. Gas Gravity:Colville River UnitColville River, Qannik Oil Pool 4000 .63. Unit or Lease Name:4. Field and Pool: 5. Datum Reference:
