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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2002 Prudhoe Oil Pool
ANNUAL RESERVOIR SURVEILLANCE
REPORT
WATER AND MISCIBLE GAS FLOODS
PRUDHOE OIL POOL
JANUARY THROUGH DECEMBER 2002
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
Page 2
CONTENTS
SECTION PAGE
1.0
2.0
3.0
4.0
5.0
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.6.1
5.1
5.2
INTRODUCTION
OVERVIEW
PRESSURE UPDATE
Pressure Monitoring
Pressure Plan
PROJECT SUMMARIES
Flow Station Two Water / MI Flood Project
Eastern Peripheral Wedge Zone Water / MI Project
Western Peripheral Wedge Zone Water / MI Project
Northwest Fault Block Water / MI Project
Eileen West End Waterflood Project
Gas Cap Water Injection Project
2003 Surveillance Plans
GAS MOVEMENT SURVEILLANCE
Gas Movement Summary
GOR Mechanisms
4
5
6
6
7
8
8
9
10
11
11
12
14
15
15
16
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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LIST OF EXHIBITS
1-A. Prudhoe Bay Unit Field Area Schematic
1-B. Well Count By Field Area Statistical Summary
1-C. Production / Injection By Field Area Statistical Summary
1-D. PBU Pressure Map
1-E. Areally Weighted Average EOA and WOA Pressures
1-F. Areally Weighted Pressure Values by Field Area
1-G. Average Monthly CGF MI Rates and Compositions
2-A. FS2 Water / MI Flood Base Map.
2-B. FS2 Reservoir Balance
2-C. FS2 Areal Average Reservoir Pressure
2-D. FS2 Daily Average RMI
3-A. EPWZ Water / MI Flood Base Map
3-B. EPWZ Reservoir Balance
3-C. EPWZ Areal Average Reservoir Pressure
3-D. EPWZ Daily Average RMI
4-A. WPWZ Water / MI Flood Base Map
4-B. WPWZ Reservoir Balance
4-C. WPWZ Areal Average Reservoir Pressure
4-D. WPWZ Daily Average RMI
5-A. NWFB Water / MI Flood Base Map
5-B. NWFB Reservoir Balance
5-C. NWFB Areal Average Reservoir Pressure
5-D. NWFB Daily Average RMI
6-A. EWE Waterflood Base Map
6-B. EWE Reservoir Balance
7-A. Wells Surveyed for Gas Movement
7-B. Gas Production Mechanisms
8. Reservoir Pressure Report
9. SI Well List
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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1. INTRODUCTION
As required by Conservation Order 341C (Approved June 12th, 1997) and 341 D (Approved
November 30th, 2001) this report provides a consolidated waterflood and gas oil contact report
summary of the surveillance activities for the Waterflood Project, Miscible Gas and Gas Cap
injection projects, and the Gravity Drainage Area within the Prudhoe Oil Pool. The time period
covered is January through December 2002.
In keeping with the requirements of the Conservation Order the report format provides
information for each of the five major flood projects and the gravity drainage project in the field,
where applicable, as follows:
• Analysis of reservoir pressure surveys and trends
• Progress of the enhanced recovery projects, including the gas cap water injection project
• Voidage balance by month of produced and injected fluids
• Data on Minimum Miscibility Pressure (MMP) of injected miscible gas
• Summary of Returned Miscible Injectant (RMI) volumes
• Results of gas movement and gas-oil contact surveillance efforts.
• Results of pressure monitoring efforts
• Table of wells shut-in during 2002 calendar year
Separate sections are provided for the five major flood areas: Flow Station 2 (FS-2), Eastern
Peripheral Wedge Zone (EPWZ), Western Peripheral Wedge Zone (WPWZ), North West Fault
Block (NWFB), Eileen West End (EWE). Information on the Gravity Drainage region is included
also. Consistent with last year’s report, data from the Eastern Operating Area (EOA) and
Western Operating Area (WOA) have been combined. Water and miscible gas floods are
described in each section. Also, a separate section has been provided with detailed information
on gas-oil contact surveillance.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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2. OVERVIEW
Exhibit 1A identifies the five flood areas and gravity drainage areas in the Prudhoe Oil Pool as
follows: FS-2, EPWZ, WPWZ, NWFB, EWE, WOA GD and EOA GD. The Waterflood Project
encompasses all five flood areas. The Prudhoe Bay Miscible Gas Project (PBMGP) is currently
active in only portions of the waterflood areas. The Eileen West End waterflood pilot concluded
in March 1999, after successfully establishing EWE injection potential. Waterflood startup
began in September 2001, EWE information has been included in this report.
Exhibit 1-B and 1-C provides well, production, and injection statistics for the major project areas
included in this report. As in last years’ report, wells do not share project boundaries, but belong
to a single project area. The well counts therefore reflect the total number of wells actually
contributing to production and injection. Similar to last year, only wells that actually produced or
injected during the year were included.
During the report period of January through December 2002, field production averaged 415
MBOD, 7567 MMSCFD (GOR 18,243 SCF/STB), and 1,115 MBWD (water-cut 73%).
Waterflood project injection during this period averaged 1045 MBWD with 372 MMSCFD of
miscible gas injection.
Cumulative water injection in the five major projects from waterflood startup through December
2002 was 8,335 MMSTB, while cumulative MI injection was 2,607 BCF. Cumulative production
since waterflood startup was 2,486 MMSTB oil, 6,594 BCF gas, and 5,035 MMSTB water. As of
December 31, 2002, cumulative production exceeded injection by 2,722 MMRB compared to
2,406 MMRB at the end of 2001. Similar to last year, production and injection values have been
calculated based upon the waterflood start-up dates for the project areas rather than of each
injection pattern.
Exhibit 1-C provides analysis of pressure static, buildup, and falloff data extrapolated to July 1,
2002 at a datum of 8,800 ft, subsea for the Full Field Dominant Zone. As in the past, abnormal
pressures, such as pressures taken in fault compartments, some injectors, and in the Sag
Formation, have been removed. The project areas pressures are continuing to decline. As of
7/1/02, average pressure in the PBU reservoir was 3,256 psia by areal weighting. Based on
known pressure decline between January and July 2002, a 42psia/yr decline rate has been
calculated. In general, pressure decline in the waterflood areas parallels the Gravity Drainage
Area..
Confirmed MI breakthrough has occurred in 214 wells during the reporting period. RMI
production is an indicator of EOR pattern performance and the presence of RMI is determined by
gas sample analyses that show a separator gas composition richer in intermediate range
hydrocarbon components.
Exhibit 1-G shows the 2002 average monthly CGF MI rates and compositions for the field.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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3. PRESSURE UPDATE
3.1 Pressure Monitoring
Exhibit 1C – 1F provide analysis of pressure static, buildup, and falloff data extrapolated to July
1, 2002 at a datum of 8,800 ft, subsea for the Full Field Dominant Zone. For this report and in
the past, pressures taken in fault compartments, the Sag River Formation, and in Zone 1 of the G-
Pad LPA (Low Pressure Area), which don’t appear to be in communication with the rest of the
reservoir, have been excluded. Although Zone 1 and Zone 4B are in poor communication with
the rest of the reservoir and therefore have low pressures, these pressures are included in the map
and calculations.
Unless otherwise noted, all pressure calculations are areally weighted, bound by the main field
original 50' LOC contour, and are referenced to a pressure datum of 8800' SS. As of 7/1/02,
average pressure in the PBU reservoir was 3256 psia by areal weighting. Average areal pressure
decline was 24 psi/yr vs the same calculation in 7/1/01.
3.1.1 Northwest Fault Block (3144 psia)
Average pressure decline for this area was 38 psi/yr, based on pressures at the start of the report
period, and mid year 2002. The pressure decline is the same as last year.
3.1.2 Western Peripheral Wedge Zone (3273 psia)
Average pressure decline for this area was 33 psi/yr, based on pressures at the start of the report
period, and mid year 2002. The pressure decline is the same as last year.
3.1.3 Eastern Peripheral Wedge Zone (3324 psia)
Average pressure decline for this area was 21 psi/yr, based on pressures at the start of the report
period, and mid year 2002.
The EPWZ receives pressure support from water/WAG injection. Faulting influences some
isolated areas and the eastern patterns show lower pressure due to out of zone injection.
Remedial action includes production to injection well conversions and fixing broken injectors to
limit out of zone injection. Such work has contributed to the leveling of pressure in this area.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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3.1.4 Flow Station Two (3312 psia)
Average pressure decline for this area was 27 psi/yr, based on pressures at the start of the report
period, and mid year 2002.
Due to the presence of areally extensive, sealing shales in the FS2 area, pressure tends to be
transmitted predominately in the horizontal plane, within hydraulic flow units. This hydraulic
unit behavior has led to the development of localized pressure sinks in the lower Romeo sands of
Drill Sites 4 and 9 and in the Zulu sands of the Drill Site 3 area. These are especially pronounced
on the eastern border where the LCU truncates the formation.
To the south, it is now understood that the high pressures seen are a result of complex, large-
scale sealing faults. Typically pressures in small-scale isolated compartments are removed when
mapping, however, this large-scale phenomenon comprises a large portion of FS-2, and therefore
these pressures have been included.
3.1.5 Gravity Drainage (3243 psia)
Average pressure decline for the Gravity Drainage area is 52 psi/yr, based on pressures at the
start of the report period, and mid year 2002. For most of the EOA GD area, pressure is
supported by the gas injection in the gas cap.
3.1.6 Eileen West End (3659 psia)
Average pressure decline for this area was 14 psi/yr, based on pressures at the start of the report
period, and mid year 2002.
3.2 Pressure Plan
Per C. O. 341C, Rule 6b, a pressure plan containing the number of proposed surveys for the next
calendar year is required to be filed with this report.
Prudhoe Bay reservoir depletion strategies are defined, and the goal of the pressure program is to
optimize areal coverage and provide sufficient data for well safety. The proposed plan for 2003
calls for collection of 120-pressure surveys fieldwide.
Per administrative approval 341C.01, dated June 22, 1999, a summary of pressure surveys run
during 2002 is presented in Exhibit 8.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4. PROJECT SUMMARIES
4.1 Flow Station Two Water / MI Flood Project
The Flow Station Two area, which comprises the eastern third of the Eastern Operating Area, is
shown in Exhibit 2-A. The locations of production and injection wells are shown with the EOR
injection patterns identified. There were 116 producing wells and 93 injection wells that
contributed to production/injection during 2002 within the FS-2 flood area. Production/injection
data was calculated with the polygon boundaries consistent with last year’s report.
The FS-2 waterflood area oil production averaged 45 MBOD for 2002 compared to 44 MBOD in
2001. Cumulative production since waterflood start-up through the end of 2002 is 944 MMSTB
of oil, 2,942 BCF of gas, and 2,531 MMSTB of water.
Waterflood injection rates averaged 642 MBWD and 140 MMSCFD in 2002. Since December of
2000, the waterflood balance has increased from a cumulative under injection of 834 MMRB to
919 MMRB under injected. During the report period, production exceeded injection by 85
MMRB. Under-injection results from the inability of tighter intervals to compete for injection
(i.e. Romeo/Victor). Waterflood strategy is to replace voidage on a zonal basis while limiting
injection rates in wells with multiple zones to avoid over injection in primary waterflood zones.
Because the reservoir balance (Exhibit 2-B) doesn't identify support from the gas-cap or aquifer,
under injection is overstated. Cumulative water injection since waterflood start-up through the
end of 2002 is 4245 MMSTB. (Production and injection values have been calculated based upon
the start-up date for the project area, 6/14/84, rather than of each injection pattern and using the
new polygon boundary.)
The flood area's GOR increased from an average of 9,725 SCF/STB in 2001 to 11,578 SCF/STB
in 2002. Gas influx continues upstructure across Drill Sites 4, 9, and 11. Gas breakthrough
continues to be present wherever gas is underrunning shales in all of the Upper Romeo and
Tango. Increases in RMI also contribute to the increased GOR. Water-cuts remained steady at
92% in 2002
A breakdown of the production and injection data is provided in Exhibit 2-B for the report
period. See Exhibit 1-C for a comparison of the cumulative figures with last year’s AOGCC
report.
Exhibit 2-C presents the areal average waterflood pressure decline over time.
Exhibit 2-D is a presentation of 2002 average returned MI (RMI) rates. Miscible gas
breakthrough has been confirmed in 54 wells by gas compositional analysis (RMI>200 MSCFD).
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4.2 Eastern Peripheral Wedge Zone Water / MI Flood Project
The Eastern Peripheral Wedge Zone (EPWZ) water and miscible gas (MI) flood area is shown in
Exhibit 3-A. In 2002, oil production averaged 24.8 MBOD with an average 87% water cut and
10,575 SCF/STB Gas Oil Ratio. Injection averaged 192 MBWD and 67 MMSCFD of miscible
injectant (MI).
There are a total of 81 producers and 55 injectors in the flood area that contributed to
production/injection during 2002. Of the 55 injectors, 16 alternately injected miscible gas and
water (WAG injectors); the remaining wells injected water only.
Production and injection values have been calculated using same polygon boundary as last years
report. Two waterflood start-up dates have been used, 12/30/82 for the DS13 flood and 8/20/84
for the down-dip sections, rather than the start-up dates of each injection pattern. A total of 555
MMSTB of oil, 1,662 BSCF of gas, and 1022 MMSTB of water have been produced with 1,503
MMSTB of water and 545 BSCF of miscible gas injected. Exhibit 3-B shows the monthly
injected and produced volumes on a reservoir barrel basis during 2002 and provides cumulative
volumes since injection began. During the report period, production exceeded injection by 60
MMRB. Because the reservoir balance doesn’t identify support from the gas-cap or aquifer,
under injection is overstated.
Exhibit 3-C shows the trend of reservoir pressure decline in the EPWZ flood area with time. The
area receives pressure support from water/WAG injection. Faulting and out of zone injection
influences the pressure in some areas. Additionally, areas of low pressure are being addressed by
strategic conversions of producers to injectors.
As cumulative MI gas injection rises, increasing gas saturations in the reservoir means larger
amounts of Returned MI (RMI) are produced in the wells. Exhibit 3-D shows the 2002 average
of estimated RMI rates in producers, as calculated from well tests and from numerous produced
gas sample analyses. Miscible gas breakthrough has been confirmed in 41 wells (RMI <200
MSCFD).
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4.3 Western Peripheral Wedge Zone Water / MI Flood Project
Exhibit 4-A is a map of the WPWZ water and miscible gas flood areas. During the report period
oil production averaged 31.3 MBOD at a gas/oil ratio of 7,136 SCF/STB and a watercut of 82%.
Injection averaged 110 MBWD of water and 75.5 MMSCFD of miscible injectant.
Production/injection data have been calculated with the 1998 polygon boundary definition.
For the WPWZ project, 69 injectors (26 WAG injectors and 43 water injectors), and 106
producers contributed to the production and injection during 2002. The well counts reflect the
number of wells actually contributing to production/injection
The waterflood startup date for the WPWZ project area was September 1985, corresponding to
the start of injection in the Main Pattern Area (MPA). The production and injection data for the
project reflect this startup date. Consistent with last year, production and injection data are
calculated on the single area basis.
Cumulative water injection from waterflood start-up through December 2002 was 1,262
MMSTB while cumulative MI injection was 478 BSCF. Cumulative production since waterflood
start-up is 434 MMSTB oil, 983 BSCF gas, and 760 MMSTB water. As of December 31, 2002
cumulative production exceeded injection by 363 MMRB. Exhibit 4-B provides the monthly
injection and production data from 01/02 through 12/02. During the report period, production
exceeded injection by 58 MMRB. During 2001, WPWZ injection targets were modified to take
into account aquifer influx occurring along the GDWFI boundary, and superpattern management
of the WPWZ waterflood to stabilize the GOC. The reservoir balance in Exhibit 4-B doesn’t
identify support from the aquifer, thereby overstating under-injection.
The areally weighted average pressure as of July 1, 2002 was 3273 psia. This represents an
average decline rate of 33 psi/yr, based on pressures at the start of the report period, and mid year
2002. Exhibit 4-C depicts the reservoir pressure history for the WPWZ area. .
Exhibit 4-D indicates wells with MI breakthrough and the 12-month averaged returned MI rates.
Miscible gas breakthrough has been confirmed in 67 wells by gas compositional analysis.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4.4 Northwest Fault Block Water / MI Flood Project
Exhibit 5-A is a map of the NWFB water and miscible gas flood areas. During the report period,
oil production averaged 25.5 MBOD at a gas/oil ratio of 6,947 SCF/STB and a watercut of 79%.
Injection averaged 78.7 MBWD and 89.3 MMSCFD of miscible injectant.
For the NWFB project, 54 injectors (21 WAG injectors and 33 water injectors), and 84 producers
contributed to the production and injection during 2002. The well counts reflect the number of
wells actually contributing to production/injection
Production and injection values have been calculated based upon the start-up date for the project
area, 8/13/84, rather than of each injection pattern and using last years polygon boundary.
Cumulative water injection from waterflood start-up in August 1984 through December 2002
was 1,316 MMSTB while cumulative MI injection was 605 BCF as detailed in Exhibit 5-B.
Cumulative production since waterflood start-up was 544.5 MMSTB oil, 960 BSCF gas, and 711
MMSTB water. As of December 31, 2002 cumulative production exceeded injection by 199
MMRB. Exhibit 5-B provides the monthly injection and production data from 01/02 through
12/02. During the report period, production exceeded injection by 50.7 MMRB.
The areally weighted average pressure as of July 1, 2001 was 3,144 psia. Average pressure
decline for this area was 38 psi/yr, based on pressures at the start of the report period, and mid
year 2002.
Exhibit 5-D indicates wells with MI breakthrough and the 12-month average returned MI rates.
Miscible gas breakthrough has been confirmed in 52 wells by gas compositional analysis.
4.5 Eileen West End Waterflood Project
Exhibit 6-A is a map of the EWE waterflood area. During the report period, oil production
averaged 18 MBOD at a gas/oil ratio of 5,431 SCF/STB and water cut of 56%. Injection
averaged 22.8 MBWD and 0.002 MMSCFD of gas.
For the EWE project, 8 injectors (2 WAG injectors and 6 water injectors), and 64 producers
contributed to the production and injection during 2002. The well counts reflect the number of
wells actually contributing to production/injection
Cumulative water injection from waterflood start-up in September 2001 through December 2002
was 9.1 MMSTB. Cumulative production since waterflood start-up was 8.4 MMSTB oil, 47 BCF
gas, and 11.1 MMSTB water. As of December 31, 2002 cumulative production exceeded
injection by 55 MMRB. Exhibit 5-B provides the monthly injection and production data from
10/02 through 12/02. During the report period, production exceeded injection by 31.4 MMRB.
The areally weighted average pressure as of July 1, 2002 was 3,659 psia. Average pressure
decline for this area was 14 psi/yr, based on pressures at the start of the report period, and mid
year 2002.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4.6 Gas Cap Water Injection Project
Details of the Volume of Water Injected during 2002 are detailed below; units in Sea Water
Injected per month (MBD):
Month PSI-01 PSI-06 PSI-08 PSI-09 PSI-10 Total
Jan 0 0 0 0 0 0
Feb 0 0 0 0 0 0
Mar 0 0 0 0 0 0
Apr 0 0 0 0 0 0
May 0 0 0 0 0 0
Jun 0 0 0 0 0 0
Jul 0 0 0 0 0 0
Aug 0 0 0 0 0 0
Sep 0 0 0 0 0 0
Oct 0 976 0 0 0 976
Nov 1,359 592 2,156 2,193 2,189 8,489
Dec 2,689 1,156 2,929 2,559 2,407 11,740
Total 4,048 2,724 5,085 4,752 4,596 21,205
Static bottom hole pressure surveys (SBHP) were taken on all five wells drilled in 2002. The
results are listed below. No additional pressure analysis was done due to the very limited volume
of water injected in 2002.
Well Date Press (psi) Datum (SS)
PSI-01 11/19/02 3412 8800’
PSI-06 11/19/02 3433 8800’
PSI-08 10/15/02 3431 8800’
PSI-09 07/30/02 3478 8800’
PSI-10 10/15/02 3492 8800’
SBHP’s were initially taken in PSI-01 on 08/21/02 and in PSI-06 on 07/19/02. In both cases
poor data was obtained and the SBHPS was repeated as shown above.
Due to project start-up in October 2002, injection didn’t ramp up to high rates until late
December 2002, hence most of the 2002 monitoring effort was focused on obtaining baseline
data. This includes the initial gravity survey completed in early winter 2002 and the baseline
RST’s run in observation wells in the Fall 2002.
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PRUDHOE BAY UNIT
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Baseline RST’s were run over the Ivishak formation in the following 11 observation wells. All
the RST’s provided quality data and will serve as a good baseline for future water movement
monitoring.
L2-28 L3-11 18-25A
L2-32 L3-19
L3-02 L5-05
L3-05 L5-09
L3-08 L5-15
The baseline surface gravity survey for the GCWI project was completed in March and April
2002. The 4D surface gravity survey will be used to monitor the reservoir density changes within
the gas cap as injection water replaces gas. The baseline survey consists of approximately 300
gravity stations. Within this baseline gravity survey, two distinct surveys were performed. One
survey used relative gravity meters and the other used absolute gravity meters. This survey
included about 40 stations that had been previously surveyed in 1994, 1997, 2000 and 2001.
These stations repeated within approximately 10-15 microGals (accounting for elevation changes
and including both gravity and elevation errors).
Theoretical gravity on the ellipsoid was computed using GRF80. All the GPS and gravity survey
data was sent to Matt Rader of the State of Alaska Department of Natural Resources on
November 20, 2002.
A baseline temperature survey was run in each of the five injectors prior to perforating and
injection. This survey will be compared to future temperature surveys to verify injection is
contained within the Ivishak formation.
The only other surveillance logs run were an injection log, water flow log, and temperature warm
back survey in PSI-06 on 11/11/02 when only Zones 1 and 2A were perforated. The goal was to
show that injection was confined to the perforated zones and not moving up hole into upper Zone
2 or Zone 3. The results showed 90% of the injection was entering the Zone 2A perfs and only
10% entering the Zone 1 perfs. This result was expected.
Three station stops were made with the water flow log at 10’, 20’, and 30’ above the top perf.
All three station stops showed no flow behind pipe. Finally the temperature warm back survey
was made. Temperature passes were made as high as 2200’ above the Ivishak formation with no
indication of water movement out of the perforated zones.
Additional conformance logs will be run in each of the injectors in 2003.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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4.6.1 2003 Surveillance Plans
Temperature warm back surveys and injection profiles are planned for each of the five injectors
this Spring. The logs will be repeated again before the end of the year. The purpose of these
logs is to demonstrate injection is confined to the Ivishak formation.
A pressure fall off test may be performed this Spring. The test is currently being planned with
the expectation it will be done on one of the injectors shortly after the warm back surveys are
complete.
RST’s will be conducted on at least six of the observation wells to see if there is any indication
of water movement. The RST’s will not be done until late in 2003 to allow time for more water
to be injected.
A second gravity survey will be conducted in March 2003. It will include both relative and
absolute measurements.
Routine monitoring of pressure and rate data will be done throughout the year. Analysis will
include Hall plots, pressure-rate plots, and bottom hole injectivity index plots.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
PRUDHOE BAY UNIT
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5. GAS MOVEMENT SURVEILLANCE
The report on gas movement surveillance activities and interpretations is broken into two major
sections. The first section provides a summary of gas influx movement and the second section
summarizes gas movement mechanisms.
5.1 Gas Movement Summary
Fieldwide GOC surveillance continues with collection of open-hole and cased-hole logs and
monitoring of well performance. In order to monitor gas movement in the reservoir, GOC
estimates are made across the field and are based upon the ongoing monitoring program and
historical well performance. The central portion of the field, the gravity drainage area (GDA)
exhibits in some areas almost total influx of the LOC (Light Oil Column). Gas influx is
essentially absent in the southern peripheral regions as a result of water and WAG injection in
the waterflood areas. .
It has become difficult in most parts of the field to define a single current GOC as the surface is
commonly broken into a series of oil lenses and gas underruns beneath the shales. The reservoir
is better characterized by a description of remaining oil targets. The targets within the GDA
occur within three general regions; the basal Romeo (Zones 1 & 2A) sands, the inter-underrun
sands, and oil lenses within the expanded GOC.
Production from the Romeo (Zones 1 & 2A) sands has historically been low compared to the
more prolific upper zones. This interval has a lower net to gross, lower permeability and more
limited sand connectivity than the rest of the reservoir. These factors impede gas expansion into
the Romeo. Underruns beneath shales within the Romeo sands are likely to be local.
The inter-underrun sands occur throughout the GDA and are characterized by one or more
underruns or solution gas pockets segmenting the remaining oil pad. Gas underruns are observed
beneath the top of the Sadlerochit reservoir, under Zone 4 shales, and the most regional persistent
underruns have developed under the mappable floodplain shales of Tango or Zone 2B.
Oil within the expanded GOC occurs in lenses above regional shales. Such lenses have been
identified from neutron logs. These lenses occur on Zulu (Zone 4B) shales, and above Tango
(Zone 2B) shales. Many lenses continue to exhibit oil drainage over time.
Exhibit 7-A lists the open and cased-hole neutron logs, as wells as RST logs, run in the Prudhoe
Bay Unit during the gas-influx reporting period from January 2002 through December 2002. A
total of 130 gas-monitoring logs, all cased-hole logs were run in the PBU.
2002 ANNUAL RESERVOIR SURVEILLANCE REPORT
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5.2 GOR Mechanisms
Exhibit 7-B lists the primary gas production mechanism for active producing. Mechanisms are
divided initially by GOR production, (L) low GOR (< 2050 scf/stb) and high GOR (> 2050
scf/stb) production. The high GOR wells are further subdivided by mechanism; (G) high GOR
production directly from the expanded gas cap (i.e. coning), (U) high GOR production from
underruns and/or solution gas pockets, (O) high GOR production due to cement channeling, high
GOR production due to commingled Sag River production, or high GOR production from
returned MI production. A more detailed discussion of each GOR mechanism is provided below:
Low GOR
Low GOR (< 2050 scf/stb) production is primarily limited to recently drilled development wells,
peripheral wells, and from waterflood project wells.
Expanded GOC
High GOR production directly from the expanded GOC occurs in numerous wells in the PBU.
As cumulative liquid voidage increases, gas influx occurs both vertically and areally. The
vertical and areal (within hydraulic layer) expansion of the original GOC gives rise to the
expanded GOC gas production mechanism.
Gas Underruns
Gas underrunning and free solution gas production contribute to high GOR production in many
PBU wells. Both underrunning and solution gas production are facilitated by continuous and
semi-continuous shale intervals. In underrunning, gas tongues connect to the expanded GOC.
Underrunning occurs upstructure in the lower formations of the reservoir and downstructure in
the upper formations.
Other
Channeling of gas via cement channels contributes high GOR and occurs in isolated cases
throughout the field. Remedial squeeze programs and sidetracking / re-drilling of compromised
wellbores has reduced the significance of this mechanism. High GOR also occurs due to
commingled production with the Sag River Formation.
Miscible gas production contributes to high GORs, but not appreciably to the movement of free
gas within the reservoir. This occurs in the gravity drainage waterflood interaction (GDWFI) and
waterflood areas and is associated with the WAG injectors.
Exhibit 1-A
Prudhoe Bay Unit Field Schematic
Exhibit 1-B
2002 BPU Overview Statistical Summary
WELL STATISTICS
WELL COUNT BY FIELD AREA
WPWZ NWFB EWE FS2 EPWZ GD
2001 AOGCC Report
Producers 106 83 54 118 76 561
Injectors 42 36 4 60 36 35
-WAG 33 32 3 37 35 2
-Water Only 9 4 1 23 1 1
-Gas 0 0 0 0 0 32
2002
Producers 106 84 64 116 81 558
Injectors 69 54 8 93 55 54
-WAG 26 21 2 25 16 2
-Water Only 43 33 6 68 39 18
-Gas 0 0 0 0 0 34
Production Well Status in 2002
-Newly Drilled 0 0 3 0 0 0
-Sidetracked or Redrilled 6 5 6 3 6 36
Gas Injection Well Status in 2002
-Newly Drilled 0 0 0 0 0 0
-Sidetracked or Redrilled 0 0 0 0 0 0
WAG Injection Well Status in 2002
-Newly Drilled 0 0 0 0 0 0
-Sidetracked or Redrilled 0 3 0 0 0 0
Water Injection Well Status in 2002
-Newly Drilled 0 0 0 0 0 5
-Sidetracked or Redrilled 1 0 0 0 0 0
NOTES:
(1) Well count data reflects ONLY those wells which contributed to production/injection during the respective year.
(2) Project boundaries were simplified in 1998. Wells no longer share project boundaries, but belong to a single project area.
(3) EOA GD and WOA GD have been combined.
Exhibit 1-C
2002 BPU Overview Statistical Summary
PRODUCTION/INJECTION STATISTICS Waterflood
Total
WPWZ NWFB FS-2 EPWZ EWE
Cumulative Production from WF Start-Up through 12/31/02
Oil (MMSTB)434 545 944 555 8 2486
Gas (BCF)983 960 2942 1662 47 6594
Water (MMSTB)760 711 2531 1022 11 5035
Cumulative Injection from WF Start-Up through 12/31/02
Water (MMSTB)1262 1316 4245 1503 9 8335
MI (BCF)478 605 979 545 0 2607
Cumulative Balance from WF Start-Up through 12/31/01
Cum Production (MMRB)1886 1789 5452 2920 13 12060
Cum Injection (MMRB)1563 1627 4583 1828 1 9602
Over/Under (MMRB)-323 -162 869 -1092 -12 -2458
Cumulative Balance from WF Start-Up through 12/31/02
Cum Production (MMRB)1997 1889 5754 3101 65 12806
Cum Injection (MMRB)1634 1690 4826 1924 10 10084
Over/Under (MMRB)-363 -199 -919 -1177 -55 -2722
MI Breakthrough in Producing Wells
> 200 mcfd 67 52 54 41 0 214
AVERAGE RATE DATA 2002
Production
Oil (MBD)31.3 25.5 45.0 24.8 18.0 144.6
Gas (MMSCFD)223.0 177.0 520.0 261.0 98.0 1279.0
Water (MBD)145.0 97.0 534.0 170.0 23.0 969.0
Injection
Water (MBD)110.0 78.7 642.0 192.0 22.8 1045.5
Gas (MMSCFD)75.5 89.3 140.0 67.0 0.0 371.8
AVERAGE RESERVOIR PRESSURE (psia)
GD WPWZ NWFB FS-2 EPWZ EWE FIELDWIDE
Beginning of report period 1/02 3269 3289 3163 3325 3334 3666 3277
Mid report period, 7/02 3243 3273 3144 3312 3324 3659 3256
Pressure Decline (psi/6 month period)26 16 19 14 10 7 21
Estimated Annual Decline (psi/yr)52 33 38 27 21 14 42
Waterflood Project Area
Exhibit 1-D
Prudhoe Bay Unit Pressure Map
Exhibit 1-G
2002 Average Monthly CGF MI Rates and MI Compositions
EOA MI Rate *MMP MW Average Monthly Mole%
MCFD PSI Mol Wt CO2 C1 C2 C3 IC4 NC4 C5+
01/02 164,720 3,744 30.39 18.40%40.77%17.77%21.35%1.04%0.67%0.01%
02/02 183,574 3,622 30.89 19.22%38.73%18.62%21.39%1.19%0.84%0.01%
03/02 222,925 3,366 31.67 19.45%35.53%19.53%23.39%1.26%0.85%0.00%
04/02 222,312 3,304 32.05 20.44%34.07%19.81%23.46%1.35%0.87%0.00%
05/02 259,755 3,389 31.85 20.73%34.75%19.94%22.34%1.25%0.97%0.02%
06/02 241,303 3,275 31.87 18.71%35.80%18.43%24.09%1.51%1.46%0.00%
07/02 161,578 3,288 31.59 17.64%36.62%18.08%25.44%1.32%0.89%0.01%
08/02 209,690 3,355 31.43 17.78%37.38%17.94%24.37%1.44%1.06%0.02%
09/02 199,767 3,422 31.38 18.63%37.22%18.44%23.44%1.31%0.93%0.03%
10/02 209,753 3,408 31.59 19.81%35.66%19.31%23.67%0.91%0.60%0.05%
11/02 217,967 3,428 31.43 18.96%37.04%18.57%23.03%1.34%1.04%0.04%
12/02 224,871 3,337 31.71 19.23%35.44%19.23%24.22%1.16%0.69%0.03%
Average 208,555 3,401 31.53 19.16%36.41%18.87%23.36%1.26%0.92%0.02%
WOA MI Rate *MMP MW Average Monthly Mole%
MCFD PSI Mol Wt CO2 C1 C2 C3 IC4 NC4 C5+
01/02 255,583 3,241 32.15 19.95%33.68%20.02%24.01%1.39%0.94%0.02%
02/02 250,231 3,498 31.08 18.27%38.32%18.28%22.89%1.35%0.88%0.01%
03/02 192,128 3,045 32.75 19.61%32.04%19.89%25.28%1.79%1.38%0.01%
04/02 176,599 3,170 32.40 20.29%32.31%20.39%25.27%1.05%0.68%0.01%
05/02 193,792 3,353 31.77 19.52%35.75%19.02%22.97%1.48%1.25%0.01%
06/02 134,339 3,066 32.60 19.17%32.86%19.28%25.56%1.60%1.54%0.00%
07/02 78,812 3,094 32.24 17.99%33.94%18.85%26.92%1.39%0.92%0.00%
08/02 99,130 3,164 32.08 18.15%34.77%18.71%25.72%1.52%1.12%0.02%
09/02 102,203 3,210 32.10 19.10%34.26%19.35%24.89%1.40%0.98%0.03%
10/02 145,830 3,168 32.44 20.47%32.11%20.42%25.40%0.96%0.61%0.03%
11/02 140,823 3,212 32.17 19.48%34.00%19.47%24.50%1.42%1.09%0.03%
12/02 164,871 3,182 32.25 19.59%33.21%19.92%25.32%1.21%0.72%0.03%
Average 159,605 3,221 32.12 19.39%34.10%19.50%24.61%1.38%1.00%0.02%
* MMP data from 1986 Zick Correlation
Exhibit 2-B
FS-2 Reservoir Balance
Cumulative
Produced Fluids
(MMRB)12/31/2001 January February March April May June
Oil 1,217.9 2.008 1.776 1.974 1.981 1.751 1.655
Free Gas 1,749.9 12.239 11.076 12.517 13.209 11.899 10.941
Water 2,421.8 18.178 16.299 18.274 17.829 14.773 15.077
TOTAL 5,389.6 32.425 29.151 32.765 33.019 28.424 27.673
Injected Fluids
(MMRB)
Water 4,083.0 24.416 22.096 24.455 24.007 18.852 16.579
Gas 472.1 1.669 1.881 2.517 2.308 3.700 3.822
TOTAL 4,555.1 26.084 23.977 26.972 26.315 22.552 20.401
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -834.5 -6.3 -5.2 -5.8 -6.7 -5.9 -7.3
Produced Fluids Cumulative
(MMRB)July August September October November December 12/31/2002
Oil 1.655 1.624 1.755 1.569 1.603 1.478 1,238.7
Free Gas 10.941 10.760 12.636 10.171 9.915 12.154 1,888.4
Water 15.077 16.563 16.586 15.387 16.912 14.669 2,617.4
TOTAL 27.673 28.947 30.977 27.126 28.430 28.302 5,744.6
Injected Fluids
(MMRB)
Water 18.496 17.530 16.969 18.903 16.585 18.899 4,320.8
Gas 2.439 3.127 2.707 2.837 2.437 3.275 504.8
TOTAL 20.934 20.657 19.675 21.740 19.021 22.174 4,825.6
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -6.7 -8.3 -11.3 -5.4 -9.4 -6.1 -918.9
Exhibit 2-C
FS-2 Areal Average Reservoir Pressure vs. Time.
3200
3300
3400
3500
3600
3700
3800
3900
4000
1/1/87 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/1/00 1/1/01 1/1/02 1/1/03 1/2/04Reservoir Pressure @ 8800' SSTVD (psia)
Exhibit 3-A
EPWZ MI Base Flood Map
Exhibit 3-B
EPWZ Reservoir Balance
Produced Fluids
(MMRB)12/31/2001 January February March April May June
Oil 718.4 1.055 0.937 1.012 1.093 1.484 0.978
Free Gas 1,055.7 7.522 6.571 6.698 6.521 6.764 6.345
Water 1,180.9 5.603 5.198 5.901 5.820 6.250 5.557
TOTAL 2,955.0 14.180 12.706 13.611 13.434 14.499 12.880
Injected Fluids
(MMRB)
Water 1,492.1 5.395 5.493 6.932 6.767 6.943 5.804
Gas 345.3 1.690 1.504 1.634 1.797 1.108 0.932
TOTAL 1,837.4 7.085 6.997 8.566 8.564 8.051 6.736
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -1,117.6 -7.1 -5.7 -5.0 -4.9 -6.4 -6.1
Produced Fluids Cumulative
(MMRB)July August September October November December 12/31/2002
Oil 0.978 0.896 0.763 0.640 0.852 0.772 729.9
Free Gas 5.836 5.183 3.602 4.692 5.382 6.793 1,127.6
Water 5.067 4.139 3.520 5.407 4.781 5.998 1,244.1
TOTAL 11.881 10.218 7.884 10.740 11.015 13.564 3,101.6
Injected Fluids
(MMRB)
Water 5.742 4.229 4.579 6.381 5.700 7.128 1,563.2
Gas 0.833 1.332 1.325 1.147 1.254 1.305 361.1
TOTAL 6.575 5.560 5.904 7.528 6.954 8.433 1,924.4
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -5.3 -4.7 -2.0 -3.2 -4.1 -5.1 -1177.2
Exhibit 3-C
EPWZ Areal Average Reservoir Pressure vs. Time.
3200
3300
3400
3500
3600
3700
3800
3900
4000
1/1/87 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/1/00 1/1/01 1/1/02 1/1/03 1/2/04Reservoir Pressure @ 8800' SSTVD (psia)
Exhibit 3-D
EPWZ Daily Average RMI
01-0701-07A 01-1001-13
01-18 03-1503-15A03-15AL1
03-2403-24A
06-0406-04A
06-0606-06A
06-09 06-1006-10A06-1106-12
06-12A
06-1306-1406-14A
06-17
06-18
06-21
07-1207-2307-24
12-01 12-02
12-0312-0412-04A
12-05 12-0612-06A
12-0712-07A
12-08
12-08A12-08B
12-08C
12-09
12-10
12-10A
12-11
12-12 12-13
12-13A
12-13B
12-14 12-14A
12-14AL1
12-14AL1PB112-14PB1
12-15
12-1612-16A
12-17 12-18
12-19 12-20 12-21
12-2212-23 12-25
12-2612-27
12-2812-28A
12-29
12-3012-31
12-32
12-33
12-34
12-35
12-36
13-01 13-0213-02A 13-02B
13-02BL1
13-03
13-04 13-05
13-06
13-06A
13-07
13-08
13-08A
13-09
13-10
13-11
13-12
13-13
13-14
13-15 13-16
13-17 13-18
13-19
13-19A
13-20
13-21
13-2213-23
13-23A
13-24
13-25
13-26
13-27
13-27A
13-28
13-29
13-29L1
13-30
13-31
13-32
13-32A
13-33
13-34
13-35
13-36
13-98
14-01 14-0214-02A 14-0314-03A
14-0514-05A
14-06
14-07
14-08
14-08A
14-08AL1
14-09
14-09A
14-09ARD
14-09B
14-10
14-11
14-12
14-13
14-14
14-1514-1614-16A
14-17
14-18
14-18A
14-19
14-19PB1 14-20
14-21
14-2214-22A
14-23
14-24
14-25
14-26
14-27
14-28
14-29
14-30
14-31 14-32
14-3414-35
14-3614-37
14-38 14-39
14-40
14-40A
14-41
14-43
14-44A
17-02
17-03
17-03A17-03APB1
17-05
17-12
17-13
17-19
17-19A
X-07
Exhibit 4-A
WPWZ MI Base Flood Map
A-01
A-01A
A-02
A-03
A-04
A-05
A-06
A-07
A-08
A-09A-09AA-10
A-11
A-12
A-13
A-14
A-15A-16
A-16A
A-17A-18
A-18A
A-19
A-20A-21A-22
A-23
A-24
A-26A-26L1
A-27
A-27A
A-29
A-30
A-31A-31A
A-32
A-32A
A-33
A-34 A-34A
A-35
A-37
A-38
A-38A
A-38L1
A-39
A-40
A-41
A-42
A-43
B-01
B-09 B-10B-11
B-12B-12AB-13
B-13A
B-21
B-24 B-25
B-31
B-32B-32AB-33B-33A
B-35
H-01
H-01A
H-02A
H-03H-06
H-09H-10H-10A
H-11H-12
H-21H-22
H-22A
H-23
H-23A
H-31
H-32H-34
H-37H-37AH-37L1
M-17A
N-03
N-10
P-01
P-02
P-02A
P-03
P-03A
P-04P-04L1
P-05P-05A
P-06
P-06A
P-08
P-08A
P-09
P-10
P-11
P-12P-12AP-12B
P-13
P-14
P-15
P-15L1
P-16
P-17
P-18P-18L1
P-19
P-22
P-23
P-24
P-25
P-25L1
P-26
U-02
U-02AU-02APB1
U-03
U-04
U-04A
U-05 U-06
U-06A U-08
U-08A
U-09
U-09A
U-10
U-11U-11AU-11B
U-12
U-13
U-14
U-15
U-15A
X-01
X-02X-04X-05X-06
X-08
X-09
X-09A
X-09B
X-10
X-11X-11A
X-12X-13X-13A
X-14X-14A
X-15
X-17
X-18
X-19X-19A
X-19B
X-19BL1
X-20
X-20A
X-21X-21A
X-22X-22A
X-23
X-24X-24A
X-25
X-26
X-27
X-28
X-28AX-29
X-30
X-31X-31L1
X-32
X-33
X-34
X-35
X-35L1
X-36
Y-01
Y-01B
Y-02
Y-02A
Y-03
Y-04
Y-05
Y-05A
Y-06
Y-07
Y-08Y-08A
Y-09
Y-09A
Y-09ACNXY-10
Y-11
Y-11A
Y-11B Y-12
Y-13
Y-14
Y-14AY-14B
Y-15Y-15A
Y-16
Y-17
Y-17A
Y-17B
Y-18
Y-19
Y-20
Y-20A
Y-21Y-21A
Y-22
Y-22A
Y-23Y-23A
Y-24
Y-25
Y-26Y-26A
Y-26L1
Y-27
Y-28
Y-29
Y-29A
Y-30
Y-30L1
Y-31
Y-32Y-32L1
Y-33
Y-34
Y-34A
Y-35
Y-35A
Y-37Y-37A
Y-38
Exhibit 4-B
WPWZ Reservoir Balance
Produced Fluids
(MMRB)12/31/2001 January February March April May June
Oil 563.5 1.381 1.269 1.392 1.264 1.357 1.405
Free Gas 568.4 5.242 4.801 5.621 5.180 5.124 4.751
Water 736.6 4.999 4.549 5.095 4.683 4.748 4.862
TOTAL 1,868.5 11.621 10.620 12.108 11.126 11.228 11.017
Injected Fluids
(MMRB)
Water 1,271.7 4.448 4.063 4.915 3.978 4.049 3.688
Gas 303.9 1.971 1.620 1.590 1.384 1.410 1.369
TOTAL 1,575.6 6.419 5.684 6.505 5.362 5.460 5.057
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -292.9 -5.2 -4.9 -5.6 -5.8 -5.8 -6.0
Produced Fluids Cumulative
(MMRB)July August September October November December 12/31/2002
Oil 1.405 1.060 1.064 1.044 1.099 1.011 578.2
Free Gas 4.597 4.569 3.701 4.228 5.113 6.741 628.1
Water 4.191 3.980 3.449 3.978 4.233 4.979 790.3
TOTAL 10.192 9.609 8.215 9.250 10.444 12.731 1,996.7
128.2
Injected Fluids
(MMRB)
Water 2.555 2.651 1.944 2.490 2.780 3.350 1,312.6
Gas 0.955 1.334 1.234 1.652 1.226 1.444 321.1
TOTAL 3.510 3.985 3.179 4.142 4.006 4.794 1,633.7
58.1
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -6.7 -5.6 -5.0 -5.1 -6.4 -7.9 -363.0
Exhibit 4-C
WPWZ Average Reservoir pressure
3200
3300
3400
3500
3600
3700
3800
3900
4000
1/1/87 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/1/00 1/1/01 1/1/02 1/1/03 1/2/04Reservoir Pressure @ 8800' SSTVD (psia)
Exhibit 4-D
WPWZ Daily Average RMI
A-01
A-01A
A-02
A-03
A-04
A-05
A-06
A-07
A-08
A-09A-09AA-10
A-11
A-12
A-13
A-14
A-15A-16
A-16A
A-17A-18
A-18A
A-19
A-20A-21A-22
A-23
A-24
A-26A-26L1
A-27
A-27A
A-29
A-30
A-31A-31A
A-32
A-32A
A-33
A-34 A-34A
A-35
A-37
A-38
A-38A
A-38L1
A-39
A-40
A-41
A-42
A-43
B-01
B-09 B-10B-11
B-12B-12AB-13
B-13A
B-21
B-24 B-25
B-31
B-32B-32AB-33B-33A
B-35
H-01
H-01A
H-02A
H-03H-06
H-09H-10H-10A
H-11H-12
H-21H-22
H-22A
H-23
H-23A
H-31
H-32H-34
H-37H-37AH-37L1
M-17A
N-03
N-10
P-01
P-02
P-02A
P-03
P-03A
P-04P-04L1
P-05P-05A
P-06
P-06A
P-08
P-08A
P-09
P-10
P-11
P-12P-12AP-12B
P-13
P-14
P-15
P-15L1
P-16
P-17
P-18P-18L1
P-19
P-22
P-23
P-24
P-25
P-25L1
P-26
U-02
U-02AU-02APB1
U-03
U-04
U-04A
U-05 U-06
U-06A U-08
U-08A
U-09
U-09A
U-10
U-11U-11AU-11B
U-12
U-13
U-14
U-15
U-15A
X-01
X-02X-04X-05X-06
X-08
X-09
X-09A
X-09B
X-10
X-11X-11A
X-12X-13X-13A
X-14X-14A
X-15
X-17
X-18
X-19X-19A
X-19B
X-19BL1
X-20
X-20A
X-21X-21A
X-22X-22A
X-23
X-24X-24A
X-25
X-26
X-27
X-28
X-28AX-29
X-30
X-31X-31L1
X-32
X-33
X-34
X-35
X-35L1
X-36
Y-01
Y-01B
Y-02
Y-02A
Y-03
Y-04
Y-05
Y-05A
Y-06
Y-07
Y-08Y-08A
Y-09
Y-09A
Y-09ACNXY-10
Y-11
Y-11A
Y-11B Y-12
Y-13
Y-14
Y-14AY-14B
Y-15Y-15A
Y-16
Y-17
Y-17A
Y-17B
Y-18
Y-19
Y-20
Y-20A
Y-21Y-21A
Y-22
Y-22A
Y-23Y-23A
Y-24
Y-25
Y-26Y-26A
Y-26L1
Y-27
Y-28
Y-29
Y-29A
Y-30
Y-30L1
Y-31
Y-32Y-32L1
Y-33
Y-34
Y-34A
Y-35
Y-35A
Y-37Y-37A
Y-38
Exhibit 5-A
NWFB MI Base Flood Map
F-18
F-19
F-24
F-30
F-33F-36
F-37
F-39
F-41
F-42
F-43F-43L1
F-48
J-06
J-07A
J-22J-22A
M-01
M-02
M-03
M-03A
M-04
M-05M-05A
M-06M-06A
M-07
M-08
M-09
M-09A
M-09B
M-10
M-11
M-12
M-12A
M-13M-13A
M-14
M-15
M-16
M-17
M-18M-18A
M-18B
M-19M-19A M-20
M-20A
M-21
M-21AM-22
M-23
M-24M-24A
M-25
M-26
M-26A
M-27
M-27A
M-28
M-29M-29A
M-30 M-31
M-32
M-33
M-34 M-38M-38A
N-04
N-05
N-08
N-08A
N-13
N-15
N-17N-18
N-19
N-23
N-23A
N-25
N-26
R-01
R-02
R-03 R-03A
R-04
R-05
R-05A
R-06
R-06A
R-07R-07A
R-08
R-09
R-09A
R-10
R-11
R-11A
R-12
R-13
R-14R-14A
R-15
R-15A
R-16R-17
R-17A
R-18
R-18A R-18B
R-19
R-19A
R-20
R-20A
R-21 R-22 R-23
R-23A
R-24
R-25
R-25A
R-26
R-26A
R-27
R-28
R-29
R-29A
R-30
R-31R-31A
R-32
R-32A
R-34
R-35R-36
R-39R-39A
R-40
S-01
S-01AS-01B
S-02
S-02A
S-03
S-04 S-05
S-05A
S-06
S-07
S-07A
S-08
S-08A
S-08BS-09
S-10S-10A
S-11
S-11A
S-11B
S-12
S-12A
S-13
S-14
S-15S-16
S-17
S-17AS-17AL1S-17BS-17C
S-18
S-18A
S-19
S-20S-20A
S-21
S-22
S-22A
S-22B
S-23
S-24
S-24A
S-25
S-25A
S-26
S-27S-27A
S-28S-28AS-28B
S-29S-29AS-29AL1
S-30
S-31
S-31A
S-32
S-33
S-34 S-35
S-36
S-37
S-38
S-40S-40A
S-41S-41L1
S-42
S-43S-43L1
S-44
S-44L1 T-01 T-07
TW-C
Exhibit 5-B
NWFB Reservoir BalanceProduced Fluids
(MMRB)12/31/2001 January February March April May June
Oil 670.6 1.173 1.059 1.159 0.913 1.143 1.077
Free Gas 464.9 4.945 4.694 5.042 4.253 4.459 4.156
Water 657.0 3.117 3.160 3.699 2.778 3.824 2.988
TOTAL 1,792.5 9.235 8.913 9.900 7.944 9.425 8.222
Injected Fluids
(MMRB)
Water 1,284.4 3.165 2.852 3.395 2.212 2.964 3.080
Gas 355.1 3.332 3.073 2.397 2.156 2.464 1.324
TOTAL 1,639.5 6.496 5.924 5.792 4.368 5.427 4.405
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -153.0 -2.7 -3.0 -4.1 -3.6 -4.0 -3.8
Produced Fluids Cumulative
(MMRB)July August September October November December 12/31/2002
Oil 1.077 0.904 0.915 0.536 0.923 0.892 682.4
Free Gas 4.282 3.522 3.078 2.886 3.511 4.033 513.7
Water 2.500 2.982 1.709 2.847 2.517 3.662 692.8
TOTAL 7.860 7.408 5.702 6.269 6.951 8.587 1,888.9
96.4
Injected Fluids
(MMRB)
Water 2.708 2.520 1.166 1.896 1.376 1.817 1,310.5
Gas 0.660 0.799 0.930 1.348 1.404 1.648 376.7
TOTAL 3.368 3.319 2.096 3.244 2.780 3.465 1,690.2
50.7
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -4.5 -4.1 -3.6 -3.0 -4.2 -5.1 -198.7
Exhibit 5-C
NWFB Areal Average Reservoir Pressure
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
1/1/87 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/1/00 1/1/01 1/1/02 1/1/03 1/2/04Reservoir Pressure @ 8800' SSTVD (psia)
Exhibit 5-D
NWFB Daily Average RMI
F-18
F-19
F-24
F-30
F-33F-36
F-37
F-39
F-41
F-42
F-43F-43L1
F-48
J-06
J-07A
J-22J-22A
M-01
M-02
M-03
M-03A
M-04
M-05M-05A
M-06M-06A
M-07
M-08
M-09
M-09A
M-09B
M-10
M-11
M-12
M-12A
M-13M-13A
M-14
M-15
M-16
M-17
M-18M-18A
M-18B
M-19M-19A M-20
M-20A
M-21
M-21AM-22
M-23
M-24M-24A
M-25
M-26
M-26A
M-27
M-27A
M-28
M-29M-29A
M-30 M-31
M-32
M-33
M-34 M-38M-38A
N-04
N-05
N-08
N-08A
N-13
N-15
N-17N-18
N-19
N-23
N-23A
N-25
N-26
R-01
R-02
R-03 R-03A
R-04
R-05
R-05A
R-06
R-06A
R-07R-07A
R-08
R-09
R-09A
R-10
R-11
R-11A
R-12
R-13
R-14R-14A
R-15
R-15A
R-16R-17
R-17A
R-18
R-18A R-18B
R-19
R-19A
R-20
R-20A
R-21 R-22 R-23
R-23A
R-24
R-25
R-25A
R-26
R-26A
R-27
R-28
R-29
R-29A
R-30
R-31R-31A
R-32
R-32A
R-34
R-35R-36
R-39R-39A
R-40
S-01
S-01AS-01B
S-02
S-02A
S-03
S-04 S-05
S-05A
S-06
S-07
S-07A
S-08
S-08A
S-08BS-09
S-10S-10A
S-11
S-11A
S-11B
S-12
S-12A
S-13
S-14
S-15S-16
S-17
S-17AS-17AL1S-17BS-17C
S-18
S-18A
S-19
S-20S-20A
S-21
S-22
S-22A
S-22B
S-23
S-24
S-24A
S-25
S-25A
S-26
S-27S-27A
S-28S-28AS-28B
S-29S-29AS-29AL1
S-30
S-31
S-31A
S-32
S-33
S-34 S-35
S-36
S-37
S-38
S-40S-40A
S-41S-41L1
S-42
S-43S-43L1
S-44
S-44L1 T-01 T-07
TW-C
Exhibit 6-A
EWE MI Base Flood Map
P-07
P-07A
P-09L1
P-20P-20A
P-20B
P-21B
W-01
W-02
W-02A W-03 W-03A
W-04
W-05
W-06W-06A
W-07
W-08
W-08A
W-09 W-10W-10A
W-11
W-12
W-12A
W-15
W-15A
W-16
W-17W-18
W-19
W-19A
W-20
W-21
W-21A
W-22
W-23
W-24W-25
W-26W-26A
W-27
W-29
W-30
W-31
W-32
W-32AW-32L1W-34
W-35 W-36
W-37W-37A
W-38
W-38A
W-39
W-40
W-42
W-44
Z-01
Z-02
Z-02A
Z-03
Z-04
Z-05
Z-06
Z-07Z-07A Z-08Z-08A
Z-09
Z-10
Z-11
Z-12
Z-13
Z-14
Z-14A
Z-15
Z-16
Z-17
Z-18
Z-19
Z-20
Z-21Z-21A
Z-22
Z-22A
Z-22B
Z-23Z-23A
Z-24
Z-25
Z-26
Z-27
Z-28
Z-29
Z-30
Z-30L1
Z-31
Z-32
Z-32A
Z-32B
Z-32BL1
Z-33
Z-33A
Z-33B
Z-35Z-38
Z-39
Exhibit 6-B
EWE Reservoir Balance
Produced Fluids
(MMRB)12/31/2001 January February March April May June
Oil 2.8 0.850 0.764 0.838 0.617 0.763 0.800
Free Gas 16.8 2.974 2.516 2.434 1.456 2.011 1.961
Water 5.6 0.819 0.747 0.821 0.593 0.922 0.885
TOTAL 25.1 4.643 4.027 4.092 2.665 3.696 3.646
Injected Fluids
(MMRB)
Water 1.1 0.433 0.395 0.637 0.537 0.753 0.772
Gas 0.0 0.000 0.000 0.000 0.000 0.000 0.000
TOTAL 1.1 0.433 0.395 0.637 0.537 0.753 0.772
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -24.0 -4.2 -3.6 -3.5 -2.1 -2.9 -2.9
Produced Fluids Cumulative
(MMRB)July August September October November December 12/31/2002
Oil 0.800 0.654 0.660 0.367 0.727 0.662 11.3
Free Gas 1.488 1.620 0.873 1.482 1.754 2.201 39.5
Water 0.651 0.762 0.340 0.686 0.585 0.752 14.2
TOTAL 2.939 3.036 1.873 2.535 3.066 3.615 65.0
Injected Fluids
(MMRB)
Water 0.620 0.881 0.500 0.804 0.882 1.226 8.8
Gas 0.000 0.000 0.000 0.000 0.000 0.004 0.0
TOTAL 0.620 0.881 0.500 0.804 0.882 1.230 9.6
Net Injection Volumes = Injection - Production (MMRB)
TOTAL -2.3 -2.2 -1.4 -1.7 -2.2 -2.4 -55.4
Exhibit 7-A
Gross Gas Influx Map
Eric Ding is presently working this section
Exhibit 8
PBU Reservoir Pressures During 2002
Well Name Test Date Tool Depth
Md
Pressure at
Tool Depth
Datum Depth
(TVD)
Pressure at
Datum
Comments
H-15 1/2/2002 11,388 3,210.90 8,800 3,211
W-21A 1/2/2002 10,305 3,336.60 8,800 3,336 Pressure at datum calculated. Initial Static Survey
17-04AL1 1/7/2002 11,003 3,414.50 8,800 3,414.50 Gradient = .388 psi/ft
Z-33A 1/17/2002 8,940 3,474.60 8,800 3,536.30 Grad = 0.094 psi/ft
W-02A 1/22/2002 10,920 3,591.40 8,800 3,591 Initial Static Pressure Survey; Datum Pressure Measured
18-09B 1/23/2002 11,922 3,305.70 8,800 3,475.33
03-32A 2/2/2002 9,442 3,415 8,800 3,415
09-49 2/2/2002 9,941 3,233.80 8,800 3,234 Datum Pressure Measured
16-14A 2/14/2002 9,980 3,347.80 8,800 3,347 Well Stable; Datum Pressure Measured
S-13 2/17/2002 10,996 3,226.60 8,800 3,268.30
W-10 2/19/2002 14,235 3,527.90 8,800 3,527.90 Datum Pressure Measured
M-31 3/2/2002 9,439 3,250.80 8,800 3,266 Datum pressure calculated by Pad Engineer
N-06 3/20/2002 10,701 3,167.80 8,800 3,174.20 Grad = 0.420 psi/ft; Well Stable
P-18L1 3/30/2002 10,975 3,308.50 8,800 3,307 7 days SI. New Well. Good data per Pad Engineer Amy Frankenburg
H-07A 3/31/2002 10,635 3,146.30 8,800 3,146 Well stable
Z-39 4/20/2002 9,380 3,630.60 8,800 3,590 Per Pad Engineer Beverly Luedke-Chan
W-09 4/21/2002 14,357 3,326 8,800 3,450 Grad = 0.413 psi/ft; Per Pad Engineer Beverly Luedke-Chan
A-12 4/22/2002 9,087 3,218.40 8,800 3,218.50 High tbg and ia press due to the injection gas not shut in the tree
03-34B 5/8/2002 9,541 2,473.60 8,800 2,538.20 Grad = 0.388 psi/ft; Datum pressure back calculated to reservoir pressure @ datum.
C-29 5/10/2002 11,643 3,218.50 8,800 3,208 Grad = 0.241 psi/ft; Datum pressure corrected to mid-perforation
C-29A 5/10/2002 11,643 3,218.50 8,800 3,218.50 Grad = 0.285 psi/ft
Q-07A 5/19/2002 11,721 3,154.40 8,800 3,154 Grad = 0.338 psi/ft; Well unstable, rising @ rate of 3.6 psi/hr @ 8800' SSTVD
J-20A 5/29/2002 11,833 3,188.70 8,800 3,189 Grad = 0.080 psi/ft;
03-23 6/2/2002 11,185 3,241.40 8,800 3,256.40 Grad = 0.15 psi/ft
03-31 6/2/2002 9,559 3,268.70 8,800 3,269 Grad = 0.448 psi/ft
09-21 6/2/2002 13,569.10 2,944.30 8,800 2,943.90 Grad = 0.299 psi/ft
09-41 6/2/2002 11,469 3,069.50 8,800 3,069.50 Grad = 0.435 psi/ft
03-20A 6/3/2002 8,897 3,263.10 8,800 3,262.90 Grad = 0.430 psi/ft
06-11 6/3/2002 10,191.10 3,286.20 8,800 3,286 Grad = 0.431 psi/ft
09-11 6/3/2002 11,783 3,213.20 8,800 3,213.20 Grad = 0.309 psi/ft
F-10A 6/3/2002 9,746.90 3,193.60 8,800 3,189.70 Grad = 0.454 psi/ft
F-31 6/3/2002 9,199.90 3,183.10 8,800 3,183 Grad = 0.190 psi/ft
03-21 6/4/2002 9,223 3,270.30 8,800 3,310.20 Grad = 0.401 psi/ft
16-15 6/4/2002 10,937 3,337.70 8,800 3,337.70 Grad = 0.424 psi/ft
16-17 6/4/2002 9,989 3,277.50 8,800 3,292.90 Grad = 0.154 psi/ft
J-08 6/4/2002 12,129 3,174.60 8,800 3,174.80 Grad = 0.371 psi/ft
04-31 6/5/2002 9,516 3,330.40 8,800 3,373.80 Grad = 0.431 psi/ft
06-19 6/5/2002 8,957 3,262.50 8,800 3,262.60 Grad = 0.429 psi/ft
01-12 6/6/2002 11,040 3,227.30
01-12 6/6/2002 11,351 3,287.40 8,800 3,287.40 Grad = 0.305 psi/ft
Exhibit 8
PBU Reservoir Pressures During 2002
Well Name Test Date Tool Depth
Md
Pressure at
Tool Depth
Datum Depth
(TVD)
Pressure at
Datum
Comments
04-35 6/6/2002 9,968 3,300.40 8,800 3,368.10 Grad = 0.339 psi/ft
16-28 6/7/2002 11,107 3,677.30 8,800 3,677.30 Grad = 0.422 psi/ft
C-11 6/7/2002 9,722 3,249 8,800 3,249 Grad = 0.08 psi/ft; Well Stable
D-05 6/7/2002 10,355 3,224.90 8,800 3,224.90 Grad = 0.077 psi/ft
17-05 6/8/2002 9,408 3,671.60 8,800 3,671.60 Grad = 0.433 psi/ft
04-07 6/13/2002 9,144 3,337.90 8,800 3,390.60 Grad = 0.438 psi/ft
H-37A 6/27/2002 10,439 2,754.50 8,800 2,754.57 Well bore gradient = 0.356032
J-10 7/3/2002 9,366 3,190 8,800 3,189.96
13-31 7/4/2002 11,838 3,435.20 8,800 3,435.20
18-14A 7/6/2002 9,903 3,283.90 8,800 3,346.03 Well Bore Gradient = 0.310658
K-20A 7/12/2002 9,601 3,226.20 8,800 3,310.70 Grad = 0.282 psi/ft
Z-09 7/12/2002 10,805 3,772.30 8,800 3,772.40
P-08A 7/15/2002 10,985 3,312 8,800 3,348.61 Well Bore Gradient = 0.415626
P-11 7/16/2002 9,401 3,179.90 8,800 3,217.68 Well Bore Gradient = 0.413655
PSI-06 7/19/2002 11,993 3,532.50 8,800 3,709.20 Initial Static; Well Bore Gradient = 0.44
01-22A 7/22/2002 10,249 3,282 8,800 3,281.98 WellBore Gradient = 0.085264
R-31 7/23/2002 10,148 3,160.30 8,800 3,199.40 Well Bore Gradient = 0.3896
GNI-02 7/24/2002 7,420 3,192.40 8,800 4,204.40
R-13 7/24/2002 9,746 3,183.10 8,800 3,179.38 Well Bore Gradient = 0.426318
18-29B 7/26/2002 9,367 3,263.50 8,800 3,341.10 Grad = 0.3099 psi/ft
C-04A 7/27/2002 10,325 3,226.80 8,800 3,226.66 Well Bore Gradient = 0.32764
C-41 7/27/2002 10,837 3,236.20 8,800 3,236.11 Well Bore Gradient = 0.336185
R-17A 7/27/2002 10,460 2,660.80 8,800 2,660.60 Well Bore Gradient = 0.334 psi/ft
14-12 7/28/2002 9,418 3,275.50 8,800 3,275.47 Well Bore Gradient = 0.408102
GNI-03 7/28/2002 7,320 3,164.70 8,800 4,154.70 well bore gradient = 0.44
K-08 7/28/2002 10,569 3,292.20 8,800 3,289.38 Well Bore Gradient = 0.356499
11-13A 7/29/2002 9,984 3,304.70 8,800 3,304.70 Well Bore Gradient = 0.153 psi/ft
04-37 7/30/2002 11,470 3,057.70 8,800 3,057.50
PSI-09 7/30/2002 10,160 3,382.20 8,800 2,828.10 Well unstable, pressure dropping 4 psi during test.
X-15A 7/30/2002 9,610 3,277.90 8,800 3,277.90 WellBore Gradient = 0.370
K-11 7/31/2002 11,327 3,345.10 8,800 3,345.10 Well Stable; Grad = 0.09 psi/ft
R-09A 7/31/2002 9,132 3,137.30 8,800 3,177 Grad = 0.465 psi/ft
K-03A 8/2/2002 9,279 3,274.20 8,800 3,370.20 Grad = 0.320 psi/ft
D-28AL1 8/3/2002 10,496 3,160.80 8,800 3,160.80 Grad = 0.332 psi/ft; Well Stable
K-07C 8/3/2002 9,637 3,334.50 8,800 3,160.60 Grad = 0.332 psi/ft
17-22 8/4/2002 10,869 3,378.50 8,800 3,378.40 Well Stable; Grad = 0.446 psi/ft
K-12A 8/4/2002 8,960 3,243.80 8,800 3,274.50 Grad = 0.153 psi/ft
K-09B 8/5/2002 9,868 3,313.30 8,800 3,313.30 GRADIENT = 0.091 psi/ft
14-11 8/8/2002 9,526 3,354.70 8,800 3,354.71 Well Bore Gradient = 0.429625
G-32A 8/11/2002 9,269 3,208 8,800 3,208 WellBore Gradient = 0.304 psi/ft
Exhibit 8
PBU Reservoir Pressures During 2002
Well Name Test Date Tool Depth
Md
Pressure at
Tool Depth
Datum Depth
(TVD)
Pressure at
Datum
Comments
04-39 8/14/2002 14,363 3,483.30 8,800 3,483
PSI-01 8/21/2002 9,000 3,147.50 8,800 3,538.70 Well Bore Gradient = 0.44
J-22A 8/26/2002 10,076 3,149.50 8,800 3,156.20 Well stable; Grad = 0.405 psi/ft
Q-03A 8/27/2002 9,102 3,139.30 8,800 3,139.30 Well Stable; Grad = 0.403 psi/ft
E-01 8/28/2002 9,394 3,304.30 8,800 3,304.30 Well Bore Gradient = 0.087 psig/ft
E-02A 8/28/2002 10,009 3,247.40 8,800 3,247.40 Grad = 0.091 psig/ft
E-04A 8/28/2002 9,987 3,199.80 8,800 3,199.80 Well Stable; Grad = 0.414 psi/ft
E-17 8/29/2002 10,908 3,303.50 8,800 3,303.50 Well stable; Grad = 0.088 psi/ft
G-04A 8/29/2002 10,259 3,234.70 8,800 3,234.90 Well Stable; Grad = 0.070 psi/ft
U-07 9/2/2002 9,657 3,243.70 8,800 3,243.70 Grad = 0.334 psi/ft
06-04A 9/7/2002 9,162 3,254 8,800 3,252.80 Grad = 0.422 psi/ft
14-01A 9/8/2002 11,093 3,257.70 8,800 3,257.90 Grad = 0.237 psi/ft
18-25A 9/9/2002 9,745 3,040.90 8,800 3,352.86 wellbore grad=0.430
18-31 9/9/2002 9,297 3,292.10 8,800 3,343.41 Wellbore gradient = 0.256
18-33 9/9/2002 11,425 3,294.20 8,800 3,311.80 Grad = 0.059 psi/ft
16-29A 9/10/2002 11,913 2,919.50 8,800 2,928 Grad = 0.366 psi/ft; Well Unstable, rising at rate of 1.37 psi/hr at 11913' MD
18-07A 9/10/2002 12,392 3,287.70 8,800 3,321.20 Grad = 0.336 psi/ft
18-27C 9/10/2002 9,657 3,273.50 8,800 3,297.40 Grad = 0.080 psi/ft
12-10A 9/11/2002 9,965 3,314.10 8,800 3,314 Well Stable; Grad = 0.423 psi/ft
GNI-01 9/11/2002 7,996 3,176.30 8,800 4,207.30 Fluid in hole is Seawater with MeOH. WHP @ surface = 400 psig.
G-23A 9/13/2002 9,054 3,197.80 8,800 3,197.90 Grad = 0.344 psi/ft; Well Stable
U-02A 9/13/2002 9,848 3,119.60 8,800 3,160.70 Grad = 0.409 psi/ft
R-23A 9/14/2002 11,708 1,291.90 8,800 1,292.14 wellbore grad=0.351
18-24AL2 9/17/2002 9,122 3,268 8,800 3,326.70 Grad = 0.293 psi/ft
R-30 9/21/2002 11,242 3,054.10 8,800 3,097.60 Grad = 0.434 psi/ft
R-39A 9/21/2002 9,253 2,985 8,800 3,032.10 Grad = 0.330 psi/ft
S-03 9/21/2002 12,010 3,552.40 8,800 3,552.30 Grad = 0.346 psi/ft
S-32 9/21/2002 10,170 3,237.70 8,800 3,237.60 Grad = 0.422 psi/ft
R-23A 9/22/2002 11,708 1,328.30 8,800 1,328.60 Grad = 0.374 psi/ft
L-01 9/25/2002 8,744 3,760.20 8,800 3,812 Grad = 0.37 psi/ft
M-07 9/25/2002 9,377 2,977.20 8,800 3,061.70 Grad = 0.422 psi/ft
M-10 9/26/2002 9,499 3,095 8,800 3,095 Well Stable; Grad = 0.420 psi/ft
M-21A 9/26/2002 9,016 3,039.80 8,800 3,083 Grad = 0.430 psi/ft
N-16 9/26/2002 9,964 3,168.80 8,800 3,200.20 Grad = 0.314 psi/ft
H-24 9/27/2002 9,777 3,214.60 8,800 3,214.70 Grad = 0.424 psi/ft
18-16B 9/30/2002 9,346 3,290.20 8,800 3,354.40 Grad = 0.321 psi/ft
18-21A 9/30/2002 10,071 3,267.90 8,800 3,311.40 Grad = 0.087 psi/ft
PSI-08 10/15/2002 13,000 3,867.70 8,800 4,039.20 Grad = 0.44 psi/ft; Initial Static Survey
H-37A 10/25/2002 10,439 2,871.70 8,800 2,871.77 Wellbore Gradient=0.334
Z-38 11/16/2002 11,748 3,796.70 8,800 3,796.70 Grad = 0.441 psi/ft
Exhibit 8
PBU Reservoir Pressures During 2002
Well Name Test Date Tool Depth
Md
Pressure at
Tool Depth
Datum Depth
(TVD)
Pressure at
Datum
Comments
PSI-01 11/19/2002 9,600 3,351 8,800 3,457.10 Grad = 0.334 psi/ft
PSI-06 11/19/2002 12,010 3,361.40 8,800 3,540.50 Grad = 0.467 psi/ft
02-12A 12/15/2002 10,166 3,254.30 8,800 3,254 Grad = 0.096 psi/ft
S-15 2/13/2003 1,086 8,800 3,336 T/I/O = 50/200/0. Tbg FL @ 1086', FP w/2000' of 60/40 MeOH
15-02A 2/16/2003 10,753 3,236.20 8,800 3,236.10 Grad = 0.221 psi/ft
M-19A 2/16/2003 9,953 3,173.20 8,800 3,203.70 Grad = 0.153 psi/ft
14-40A 2/27/2003 9,561 3,157.20 8,800 3,328.60 Grad = 0.430 psi/ft
Exhibit 9
Shut-in Well List
Sw Name Shut-in
Date
Reason for
Well
Shut-InA
Future Utility
Plans
& PossiblitiesB
Current Mechanical Condition/ Additional Comments
1 01-01B Mar-99 6 5 CT cemented high in production tbg in 1993
2 01-05 May-98 6 5 Ann Comm: RWO Unecon
3 01-17A Jun-00 3 5 Low rate, high GOR, thin LOC in area
4 01-19A Oct-01 7 3 New ST produces gunk, waiting on SL to evaluate
5 01-20 Jun-00 6 7 Multiple holes in tbg, waiting on patch; on RWO list
6 01-30 Apr-97 6 5 Cretaceous leak, thin LOC
7 03-05 Mar-91 6 5 Temp P&A, BHL replaced
8 03-30 Dec-01 2 5 ST not economic
9 03-32A Nov-01 2 2 IAxOA on AL; not a good WSO candidate
10 04-04A Jan-95 6 5 CTD BHA stuck in a window, junked
11 04-07 Jan-97 2 5 Will BOL w/ UDVW project, Don't know test data
12 04-12 Jun-94 6 5 LTSI: geophones cemented in hole
13 04-21 Oct-99 6 1 RWO's been approved for years
14 04-34A Mar-94 2 5 High WC. No ID utility.
15 04-36 Nov-01 2 5 High WC. No ID utility.
16 04-39 Apr-98 2 5 High WC. No ID utility.
17 04-40 Aug-01 6 1 Tbg leak, eval options.
18 04-46 Nov-01 2 5 High WC. No ID utility.
19 05-11A May-01 3 2
20 06-06A Aug-96 6 5 CT fish in hole
21 06-13 Oct-01 3 2 poor cycler; T x IA x OA communication
22 06-16 Jun-01 6 2 T x IA x OA communication
23 06-21A Dec-01 6 2 T x IA communication
24 06-22A Jun-99 6 5 Severe Ann Comm
25 07-27 Aug-90 6 5 Coil in holer
26 09-03 May-01 2 5 IAxOA small. Requested to BOL for waiver eval.
27 09-36C Dec-01 3 2 Low GFR.
28 11-09A Aug-00 6 5 LTSI; TxIA, obstruction
29 11-12 Jan-94 6 5 Severe mech integrity. No current utility.
30 11-15 Jan-90 6 5 P&A'd?
31 11-23A Feb-98 2 2
High WC (twinned & can't compete w/ HP well.
Uneconomic de-twin. Potentially and UDVW injection conversion
32 11-38A Jan-01 7 2 Tbg leaks. Uneconomic RWO. Conversion to wtr only injector package in the works
33 12-05 Feb-00 6 5 Ann Comm: RWO Required
34 12-11 Feb-00 1 5 High TGOR
35 12-12 Sep-01 6 2 Tbg patch needs replaced
Sw Name Shut-in
Date
Reason for
Well
Shut-InA
Future Utility
Plans
& PossiblitiesB
Current Mechanical Condition/ Additional Comments
36 12-34 Sep-01 2 5 RWO/Conv planned
37 13-05 Nov-97 1 5 LTSI. Next to MI injector
38 13-07 Jun-91 3 5 Low Qo, High TGOR (SI 10/90)
39 13-10 Jun-94 2 5 Ann Comm: uneconomic RWO
40 13-13 Aug-97 2 5 Ann Comm: uneconomic RWO
41 13-26 Feb-97 2 5 Ann Comm: Uneconomic RWO
42 13-28 May-94 2 5 Low oil, High TGOR
43 13-33 Dec-94 1 5 Low oil, High TGOR
44 14-02B Apr-00 1 2 Waiting for response to planned PWI conversion nearby
45 14-11 Aug-98 6 2 LTSI (facilities status?) Eval for Rig ST
46 14-15 Sep-01 6 7 TxIA. RWO for SWIPE(likely post'03)
47 14-18A May-00 3 3 Eval for ST
48 14-20 Feb-00 6 7 TxIA. Hole 5588. RWO for SWIPE (likely post '03)
49 14-38 Nov-94 3 2 Low Qo, High TGOR (SI 11/94) TxIA and low PI. Eval ST
50 14-39 Jun-94 6 5 IAxOAxForm. Leak @ 81'. No flowline.
51 14-41 Apr-00 1 2 Eval ST options.
52 15-03 Jun-94 6 5 Cret leak, leaking sqz perfs, major fish in tubing; surface facilities given to another well
53 15-10A Jan-91 6 5 Major leaks and a channel; no surface facilities; bottom hole location developed by 15-49
54 15-24 Mar-95 6 5 Collapsed tubing, cret leak.
55 16-24 Aug-96 2 5 Was MIST injector; now SI for Res Management
56 16-31 Apr-95 3 5 Was possible MIST candidate but tbg leaks on gas
57 17-13 Jun-01 3 2 RST, but uneconomic.
58 A-06 Dec-95 1 6 No Facilities - need to evaluate
59 A-25A Nov-97 7 5 LTSI - no tubing in well
60 A-41 Sep-00 6 7 LTSI - cretaceous leak. Sidetrack w/ RWO.
61 B-02A Jun-01 6 1 Tbg x world communication
62 B-11 Jan-91 3 5 surface facilites given to B-35
63 B-15 Nov-99 6 7 RWO/Conv planned
64 B-17 May-00 6 7 RWO/Conv planned
65 B-22A Aug-99 2 4 Conversion potential
66 B-24 Jan-93 6 5 Aban in early 90's
67 B-29A Oct-01 1 5 Gas production from liner lap. Needs more IOR for GSO.
68 C-14 May-91 1 5 SI fo high GOR, facilities taken.
69 C-26A Apr-01 1 3 Sidetrack package issued.
70 C-38 Nov-97 6 5 Cretaceous leak, flowline taken, eval ST.
71 F-07 Jul-91 6 5 FL gone -no tbg
Exhibit 9
Shut-in Well List
Sw Name Shut-in
Date
Reason for
Well
Shut-InA
Future Utility
Plans
& PossiblitiesB
Current Mechanical Condition/ Additional Comments
72 F-18 Sep-99 6 5 FL Gone
73 F-19 Aug-96 6 5 Fl Gone
74 H-01A Jun-99 6 7 Slickline work on WOBL to investigate non-rig options.
75 H-05 Dec-01 6 2 May revisit cleanout pending anncomm investigation.
76 H-10A Oct-97 6 5 Lost source in hole - Plugged
77 H-12 May-91 6 5 Csg collaspe appx 2000 ft
78 H-18 Aug-00 6 7 RWO package ready, $2.11/bbl.
79 H-28 Apr-01 6 2 ST target available, but probably cheaper from Q-pad.
80 J-04 May-96 6 5
81 J-06 Jun-96 6 5 Mature GDWFI, watered out, has 7" tubing w/ POGLM holes
82 J-07A Jun-00 6 7 Collapsed tubing. RWO on books
83 K-04A Mar-01 3 3 RST scheduled for Arpil
84 K-10A Jul-01 2 2 Wellbore placed to high in structure. Very low value.
85 K-13 Oct-97 6 7 Safed out with TTPlug. Small leak produces oil to cellar.
86 L2-08A Aug-99 3 5 No current plans for this wellbore.
87 L2-18A Jul-01 6 2 Tbg and casing damaged. CTST planned but put on hold due to mechanical issues.
88 M-09A Dec-99 3 4 Low PI, High WC. Poten Conv.
89 M-19A Apr-01 6 1 Ann Comm well, POGLM is on WWBL
90 M-27A Jul-97 3 5 LTSI, low rate, money pit
91 M-31 Apr-01 7 6
Twin competition, de-twin in progress, waiting on slope facility design group
(also has minor Ann Comm issues to be dealt with once the well is POP'd)
92 N-02 Jul-88 6 5 equipped has been moved
93 N-03 Jan-96 6 5 Wtr in cellar and high Wtr Cut
94 N-05 Aug-84 6 5 ann com - equipped removed
95 N-06 Sep-01 7 4 Promising LTSI well. Work on WOBL for gaslift.
96 P-22 Dec-96 3 5 LTSI. No oil. Sidetrack candidate.
97 Q-03A Dec-01 3 1 well dead following CIBP. WW planned
98 Q-04A May-01 6 2 Rotten tubing. Under eval for CTD ST & inner string
99 R-01 Nov-93 6 5 Ann Comm. No flowline or wellhouse. Replaced by R-39
100 R-04 Aug-01 4 1 Frozen flowline. POP in summer.
101 R-10 Mar-01 3 5 LTSI, low rate (also has Ann Comm issues)
102 R-13 Aug-99 1 5 LTSI, high GOR (also has Ann Comm issues)
103 S-10A Nov-91 2 5 Never completed, No tbg. Eval ST
104 S-13 Mar-01 2 7 SI for high WC, has failed pkr, ST candidate
105 S-27A Apr-96 3 2 Low PI, Needs OA sqz. Low prior. Orig logs? LTSI
106 U-06A Feb-00 3 5 Watered out. Failed TIT for sidetrack.
Exhibit 9
Shut-in Well List
Sw Name Shut-in
Date
Reason for
Well
Shut-InA
Future Utility
Plans
& PossiblitiesB
Current Mechanical Condition/ Additional Comments
107 U-07 Aug-93 2 5 LTSI. No flowline, poten ST?
108 U-12 Jan-99 7 5 P&A'd. Tbg corrosion. Lost well during sidetrack
109 W-07 Oct-01 6 5 bad tbg.=no patch. Not enough reserves for RWO
110 W-17 Feb-99 6 2 IAxOAxTbg lk. Maybe future ST
111 Y-08A Sep-93 3 2 No Facilities - Eval ST
112 Y-12 May-99 6 2 TxIAxOA comm FTS well - secured
113 Y-22A Jan-90 2 5 LTSI…suspended & BHL re-drilled as Y-25
114 Y-31 Oct-93 3 2 Low GFR. Evaluating sidetrack.
115 Y-34A May-99 3 2 Low GFR. Sidetrack candidate.
116 Y-35 Apr-99 6 5 Coil Cemented in Hole
117 Y-38 Dec-01 3 2 Low GFR and collapsed tbg. Sidetrack candidate.
118 Z-04 Oct-98 7 5 no surface facilites + bad tbging
119 Z-07A Oct-98 7 5 no surface facilites
120 Z-12 Oct-98 2 5 watered out. Channel to aquifer
121 Z-15 Oct-98 7 2 corroded flowline. Needs Z3 sqz
122 Z-19 Jul-96 6 5 Tubing integrity, no flowline. Testing quality?
123 Z-20 Feb-98 1 5 High GOR, 100' from injector
124 Z-35 Apr-01 3 5 Low PI, completion problems also, poor rock Q
125 Z-37 Jan-99 3 5 Never produced?
126 Z-38 Dec-01 4 1 rock producer. Needs liner patch.
Exhibit 9
Shut-in Well List
A. Reasons for Well Shut-In
1. High GOR,curently uncompetitive to produce due to facility constraints, no known mechanical problems
2. High water, currently uneconomic to produce, no known mechanical problems
3. Low production rate, no known mechanical problems
4. Wellwork
5. Reservoir Management
6. Mechanical Problem
7. Other (Specify under comments)
B. Future Utility
1. Wellwork Planned
2. Under Evaluation
3. Sidetrack Planned
4. Reservoir Management
5. No Current Utilization
6. Surface Facilities
7. RWO Candidate
Exhibit 1-E
Areally Weighted Average Pressures
EOA PRESSURE TRENDS (areally wtd avgs)
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
12/31/82 12/31/83 12/31/84 12/31/85 12/31/86 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/2/00 1/1/01 1/1/02 1/2/03 1/2/04
P
S
I
A
FS2
EPWZ
EOAGD
WOA PRESSURE TRENDS (areally wtd avgs)
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
12/31/82 12/31/83 12/31/84 12/31/85 12/31/86 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/2/00 1/1/01 1/1/02 1/2/03 1/2/04
P
S
I
A
NWFB
WPWZ
WOAGD
AREAL AVG. P in the PBMGP
(FS 2,EPWZ,WPWZ,NWFB)
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
12/31/82 12/31/83 12/31/84 12/31/85 12/31/86 1/1/88 12/31/88 12/31/89 1/1/91 1/1/92 12/31/92 1/1/94 1/1/95 1/1/96 1/1/97 1/1/98 1/1/99 1/2/00 1/1/01 1/1/02 1/2/03 1/2/04
P
S
I
A
DATE FS2 EPWZ EOAGD WPWZ NWFB WOAGD PBMGP
12/31/77 3935 4005 4021 4016 3944 3977 3968
7/1/78 3870 3967 3987 3978 3909 3939 3914
12/31/78 3832 3930 3957 3944 3875 3908 3873
7/2/79 3813 3895 3924 3911 3843 3877 3844
12/31/79 3791 3861 3891 3879 3799 3850 3816
7/1/80 3799 3831 3891 3848 3770 3821 3798
12/31/80 3852 3819 3845 3822 3781 3800 3818
7/1/81 3881 3821 3833 3799 3814 3784 3840
12/31/81 3880 3815 3818 3799 3820 3768 3842
7/2/82 3872 3806 3803 3800 3812 3753 3833
12/31/82 3850 3795 3785 3797 3804 3739 3818
7/2/83 3831 3784 3768 3792 3787 3722 3804
1/1/84 3814 3771 3751 3783 3772 3704 3790
7/1/84 3796 3758 3735 3777 3756 3686 3774
1/1/89 3779 3743 3719 3771 3736 3670 3755
7/1/89 3760 3730 3703 3763 3723 3653 3740
1/1/90 3732 3708 3685 3731 3704 3631 3713
7/1/90 3708 3693 3668 3716 3687 3613 3695
1/1/91 3680 3676 3650 3694 3655 3595 3666
7/1/91 3642 3657 3633 3673 3628 3576 3635
1/1/92 3617 3641 3617 3652 3602 3558 3615
7/1/92 3591 3626 3600 3632 3577 3540 3593
1/1/93 3561 3600 3576 3619 3544 3522 3582
7/1/93 3543 3595 3560 3598 3515 3502 3565
1/1/94 3539 3555 3542 3578 3483 3482 3537
7/1/94 3523 3536 3527 3555 3456 3457 3516
1/1/95 3496 3524 3517 3555 3507 3447 3506
7/1/95 3473 3507 3503 3536 3489 3428 3486
1/1/96 3466 3485 3485 3497 3478 3407 3463
7/1/96 3450 3467 3470 3472 3461 3390 3443
1/1/97 3446 3484 3435 3460 3444 3373 3441
7/1/97 3429 3467 3416 3438 3427 3357 3421
1/1/98 3452 3417 3413 3417 3421 3344 3430
7/1/98 3435 3409 3397 3394 3402 3328 3415
1/1/99 3445 3391 3376 3382 3343 3302 3443
7/1/99 3429 3378 3361 3360 3317 3285 3426
1/1/00 3406 3361 3356 3372 3268 3231 3418
7/1/00 3390 3351 3342 3353 3240 3203 3395
1/1/01 3366 3325 3323 3325 3225 3224 3358
7/1/01 3360 3310 3309 3309 3205 3205 3347
1/1/02 3325 3334 3296 3289 3163 3245 3358
7/1/02 3312 3324 3279 3273 3144 3211 3347
1/1/03 3298 3313 3261 3256 3124 3177 3335
Exhibit 1-F
Areally Weighted Average Pressures
Exhibit 2-A
FS-2 MI Flood Base Map
Exhibit 2-D
FS-2 Areal Average RMI
Exhibit 7-A
Well Surveyed for Gas Movement
Well Log Date OH / CH Well Log Date OH / CH Well Log Date OH / CH
01-07A 2/15/2002 CH 14-32 7/20/2002 CH J-01A 5/11/2002 CH
12-Jan 9/2/2002 CH 14-33 7/21/2002 CH J-01B 11/21/2002 CH
01-12A 10/30/2002 CH 15-29A 2/25/2002 CH J-08 1/11/2002 CH
01-15A 2/8/2002 CH 15-31A 6/15/2002 CH J-09A 9/26/2002 CH
16-Jan 7/26/2002 CH 18-05 8/19/2002 CH J-10A 9/15/2002 CH
01-19A 11/5/2002 CH 18-18B 8/9/2002 CH J-15B 10/7/2002 CH
01-22A 10/9/2002 CH 18-25A 10/22/2002 CH J-16 2/23/2002 CH
01-26A 11/8/2002 CH 18-29B 4/10/2002 CH J-17B 1/18/2002 CH
31-Jan 1/9/2002 CH 18-32A 3/31/2002 CH J-18 2/1/2002 CH
01-32A 11/7/2002 CH 18-34 8/10/2002 CH J-20B 10/17/2002 CH
01-32A 12/18/2002 CH A-28 11/21/2002 CH J-27A 11/13/2002 CH
01-32A 11/27/2002 CH B-07 4/13/2002 CH J-27A 11/15/2002 CH
02-02A 10/25/2002 CH B-23A 4/29/2002 CH K-02C 1/19/2002 CH
02-12A 12/29/2002 CH C-02 7/3/2002 CH K-05B 1/7/2002 CH
02-13B 2/8/2002 CH C-09A 9/8/2002 CH K-05B 7/12/2002 CH
28-Feb 5/24/2002 CH C-09A 5/12/2002 OH K-09B 1/31/2002 CH
02-32B 3/6/2002 OH C-11 12/26/2002 CH K-19A 4/4/2002 CH
Feb-37 10/27/2002 CH C-16 7/23/2002 CH K-20A 3/8/2002 CH
9-Mar 11/12/2002 CH C-19B 4/21/2002 CH M-12A 4/25/2002 CH
05-02A 2/6/2002 CH C-25A 7/10/2002 CH M-24A 4/13/2002 CH
05-26A 1/12/2002 CH C-31A 7/13/2002 CH N-11B 8/6/2002 CH
05-32A 3/5/2002 CH D-08A 7/15/2002 CH N-15 11/13/2002 CH
1-Jun 7/7/2002 CH D-17B 6/24/2002 OH PSI-06 11/11/2002 CH
07-13B 7/7/2002 CH D-22B 6/9/2002 CH PSI-06 6/21/2002 CH
22-Jul 12/16/2002 CH E-03A 2/13/2002 OH PSI-09 7/18/2002 CH
07-28A 3/28/2002 CH E-08A 8/27/2002 CH PSI-10 8/27/2002 CH
Jul-36 6/12/2002 CH E-08A 8/24/2002 CH Q-07A 6/12/2002 CH
09-07A 9/12/2002 CH E-09B 9/7/2002 CH R-29A 7/20/2002 CH
09-28A 8/10/2002 CH E-21A 4/3/2002 CH R-29A 7/21/2002 CH
09-28A 11/10/2002 CH E-25 2/21/2002 CH W-04 8/11/2002 CH
29-Sep 12/15/2002 CH E-31A 8/8/2002 CH W-04 8/1/2002 CH
11-05A 10/30/2002 CH E-31A 8/9/2002 CH W-18 7/27/2002 CH
6-Nov 11/20/2002 CH E-31A 5/21/2002 CH W-20 8/12/2002 CH
18-Nov 9/7/2002 CH E-33 6/3/2002 CH W-20 7/28/2002 CH
11-24A 7/6/2002 CH F-08 9/11/2002 CH W-22 8/1/2002 CH
11-28A 12/13/2002 CH F-26A 2/22/2002 CH W-25 7/30/2002 CH
Nov-33 9/13/2002 CH F-26A 2/21/2002 CH W-29 7/29/2002 CH
26-Dec 7/22/2002 CH G-06 12/29/2002 CH W-30 8/2/2002 CH
14-02B 7/4/2002 CH G-10B 6/29/2002 CH W-36 8/1/2002 CH
14-05A 7/6/2002 CH H-08 10/15/2002 CH W-37A 12/4/2002 CH
14-12 7/8/2002 CH H-20 10/9/2002 CH W-39 9/9/2002 CH
14-23 7/9/2002 CH H-23A 10/12/2002 CH Y-36 5/30/2002 CH
14-24 7/10/2002 CH H-30 6/13/2002 CH
14-31 7/11/2002 CH H-36A 5/7/2002 CH OH Open Hole Log
CH Cased Hole Log
Exhibit 7-B
Gas Production Mechanisms
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
01-02 G 02-15A G 03-30 L
01-03A G 02-16A U 03-31 U
01-04A G 02-17A U 03-32A O
01-06A U 02-18A G 03-34B O
01-07A G,O 02-19 U 03-35 O
01-10 G 02-20 G,U 04-01 G
01-12 G 02-21A G,U 04-02A G
01-12A G 02-22A G,U 04-03 G
01-13 G 02-23A G 04-05A U
01-14 G 02-24 G 04-16A U
01-15A G 02-25 U 04-18 L
01-16 G,U 02-26B U 04-21 G
01-18 G 02-27A U 04-22A U
01-19A G 02-28 U 04-23A L
01-20 G,U 02-29A G 04-24 U
01-21 G,U 02-30B U 04-26 L
01-22A G,U 02-31A G 04-29AL1 L
01-23 G 02-32B U 04-30 G
01-24A G 02-33A G 04-31 U
01-25 G 02-34A U 04-32A L
01-26A G 02-35A U 04-33 U
01-28 G 02-36 U 04-34A U
01-29 G,U 02-37 G 04-35 G
01-30 G 02-38L1 U 04-37 U
01-31 G 02-39L1 U 04-38 L
01-32 G,U 03-01 G 04-41A U
01-32A U 03-02 L 04-47 L
01-33 G 03-03 O 04-48 U
01-34 O 03-08 L 05-01C G
02-01B G 03-09 U 05-02A G,U
02-02A G 03-14 L 05-03C G
02-03B U 03-15A O 05-04A U
02-04A U 03-15AL1 O 05-05B O
02-05 U 03-19 L 05-06A U
02-06A U 03-20A O 05-07 G
02-07A U 03-21 L 05-08 G
02-08B U 03-22 U 05-09A G
02-09B U 03-23 G,U 05-10B G
02-10B U 03-24A G 05-11A G
02-11A U 03-25A O 05-12B G
02-12A U 03-26 O 05-13A G
02-13A U 03-27 O 05-14A G
02-13B G 03-28 G,U 05-15B G
02-14 U 03-29 U,O 05-16B G
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
05-17B G 06-24A G 09-23A L
05-18A O 07-01A U,O 09-24 O
05-19 G 07-02A U,O 09-26 O
05-20A G 07-03A U,O 09-27 O
05-21A U 07-04A G 09-28A O
05-22A G 07-05 U 09-29 O
05-23A G 07-07A G,O 09-30 O
05-24 G 07-09 G,O 09-31C U
05-25B G 07-10A U,O 09-32 U
05-26A G 07-12 U,O 09-33 U
05-27A U 07-13A U,O 09-34A O
05-28A G 07-13B #N/A 09-35A U
05-30 G 07-14A U,O 09-41 O
05-31A U 07-15A U 09-42A O
05-32A G 07-16A U 09-43 O
05-33A G 07-17 U 09-44 O
05-34 G 07-18 G,O 09-45 O
05-36 G 07-19A U 09-46 O
05-38 G 07-20A U,O 09-47 O
05-39 G 07-21 G 09-48 U
05-40 U 07-22 G 09-49 O
05-41 G 07-23A G 09-50 O
06-01 G 07-24 G 09-51 O
06-02 G 07-25 G,O 11-01A L
06-03A G 07-26 G 11-03A O
06-04A G 07-28A U 11-04A U
06-05 G 07-28AL1 O 11-05A U
06-07 G 07-29A G 11-06 U
06-08A G 07-30 G,O 11-11 L
06-09 G 07-32A G 11-13A G
06-10A U 07-34A U,O 11-16 G
06-11 G 07-35 U 11-17A U
06-12A G 07-36 U 11-18 U
06-13 G 07-37 U 11-22AL1 U
06-14A G,U 09-01 O 11-23A L
06-15 G,U 09-02 O 11-24A U
06-16 G 09-04A O 11-25A U
06-17 G 09-05A O 11-27 U
06-18 G,U 09-06 #N/A 11-28A U
06-19 G,U 09-07A O 11-30 U
06-20 G 09-09 O 11-31A L
06-21A G 09-11 O 11-32 L
06-22A G 09-13 O 11-33 L
06-23A G 09-21 O 11-34 U
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
11-36 L 14-03A G 15-16A G
11-37 U 14-04A G 15-17 G
12-01 U 14-05A G 15-18 U
12-03 O 14-06 O 15-19A O
12-04A O 14-07 G 15-20A G
12-05 O 14-08A O 15-21A G
12-06A L 14-08AL1 L 15-22 G
12-07A O 14-09B L 15-23 G
12-08B O 14-10 O 15-25A G
12-08C U 14-12 G 15-26A G
12-09 O 14-16A G 15-27 G
12-10A L 14-19 O 15-28 G
12-11 U 14-20 G 15-29A G
12-12 O 14-22A O 15-30 G
12-13B O 14-23 G 15-31 G
12-14A O 14-24 G 15-31A G
12-14AL1 U 14-26 G 15-32A G
12-15 O 14-28 G 15-33A G
12-16A L 14-29 G 15-34A G
12-17 U 14-30 G 15-35 O
12-18 U 14-31 U 15-36A G
12-22 L 14-32 G 15-37A G,O
12-26 G 14-33 U 15-38 G
12-28A G 14-34 G 15-40A G
12-29 G 14-37 O 15-41B U
12-32 G 14-39 L 15-42A G
12-35 L 14-40A L 15-43 G
12-36 L 14-41 U 15-44 G
13-01 O 14-43 U 15-45A G
13-02BL1 O 14-44 O 15-46 U
13-03 O 14-44A L 15-47 U
13-04 O 15-01A U 15-49A G
13-08A O 15-02A U 16-04A L
13-11 O 15-04 U 16-06A O
13-12 O 15-05A U 16-07 O
13-14 O 15-06A U 16-08A L
13-26 L 15-07B G 16-09A L
13-27A O 15-08B U 16-12A L
13-29 L 15-09A G 16-13 L
13-29L1 L 15-11A U 16-15 L
13-30 O 15-12A G 16-17 O
13-33 O 15-13A G 16-18 O
13-34 L 15-14 G 16-19 O
14-02B G 15-15A G 16-20 O
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
16-21 L 18-22A G B-05B U, G
16-22 L 18-23A G B-06 U,G
16-23A L 18-24AL2 G B-07 U,G
16-25 O 18-25A G B-08 U
16-26A L 18-26A G B-10 U
16-27A L 18-27C G B-12A G
16-28 L 18-29B G B-14 G
16-29A L 18-30 G B-16 U,G
16-30 O 18-31 G B-18 U,G
17-01 U 18-32A G B-19A U,G
17-02 O 18-33 G B-20 U,G
17-03A L A-01A O B-21 G
17-04AL1 O A-02 G B-23A U
17-05 O A-04 G B-25 G
17-07 L A-07 G B-26B G
17-09 O A-09A G B-27A U,G
17-11 L A-10 G B-30A G
17-12 O A-12 L B-33A G
17-14 O A-13 G B-35 G
17-16 O A-14 L B-36 U
17-19A O A-15 L C-01 G
17-20 O A-18A L C-02 G
17-21 L A-19 L C-03A G
17-22 L A-20 L C-04A G
18-02A G A-22 L C-05A U
18-04B G A-23 G C-06A G
18-05 G A-24 G C-07A G
18-05A L A-26 L C-08A G
18-06A G A-28 G C-09A G
18-07A G A-29 G C-10 G
18-08A G A-30 L C-12A G
18-09B G A-32A L C-13A G
18-10B U A-33 L C-17A G
18-11DPN G A-34A L C-18A G
18-12A G A-37 L C-19B G
18-13A G A-38 L C-20B G
18-14A G A-38L1 L C-21 G
18-16B G A-39 L C-22 G
18-17 G A-40 L C-25A G
18-18A G A-42 L C-27A G
18-18B U A-43 G C-28A G
18-19 G B-01 G C-29A O
18-20 G B-03B G C-30 U
18-21A G B-04 U,G C-31A G
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
C-33A G E-04A G F-15 G G-16 O
C-34 U E-05A G F-16A U G-17 G
C-35A O E-06A L F-17A G G-18A G
C-36A G E-07A G F-21 G G-19A O
C-37A U E-08 G F-22 G G-21 G
C-39 U E-08A G F-23A U G-23A G
C-41 G E-09A G F-24 U G-24 O
C-42 G E-09B G F-26A U G-25A G
D-01A U E-10A G F-27 U G-26A O
D-03A U E-12 U F-28 U G-27 G
D-04A U E-14A O F-29 G G-29A G
D-05 U E-15B G F-30 G G-30A O
D-06A U E-16 O F-31 G G-31A G
D-07A U E-17 G F-32 O G-32A G
D-08A L E-18A G F-34A G H-04 G
D-09A U E-19A O F-35 G H-06 U
D-10 G E-21A G F-36 O,G H-07A G
D-11A G E-23B G F-37 G H-08 G
D-12 G E-24B G F-39 O,G H-11 U
D-13A U E-25 G F-40 U H-13 G
D-14A U E-26A O F-41 G H-14A G
D-15A G E-27A G F-42 G H-15 G
D-16 U E-28A G F-43 G H-16B G
D-17B G E-29 G F-43L1 O,G H-17A G
D-18A U E-31A G F-44 G H-19B G
D-19B U E-32A G F-45 U H-20 G
D-20 U E-33 G F-46 G H-21 G
D-21 U E-34 O F-47A U H-22A U
D-22A G E-35A G F-48 O H-23A G
D-22B U E-36 G G-01A G H-24 U
D-23A G E-37 G G-02A G H-25 G
D-24 G E-38 O G-03A U H-26 G
D-25A U E-39 O G-04A O H-27 G
D-26A U F-01 U G-05 G H-29A G
D-27 U F-02 G G-07 O H-30 G
D-28A G F-03A G G-08 G H-32 U
D-28AL1 G F-04 G G-09A U H-33 G
D-29 U F-05 G G-10A G H-34 U
D-30 G F-08 G G-10B G H-35 G
D-31A G F-09A G G-11A O H-36A G
D-33 U F-11A U G-12A G H-37A O
E-01 G F-12 G G-13A G J-01A G
E-02A G F-13A U G-14A G J-01B G
E-03A G F-14 O G-15A O J-02A G
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
J-03 G K-19A G N-21A G
J-05B G K-20A G N-22A G
J-08 G L-01 L N-24 G
J-09A G L2-03A G N-25 U
J-10 U L2-07 G N-26 O
J-10A G L2-11 G P-01 O
J-11A G L2-13A G P-04L1 O
J-12 G M-04 O P-05A L
J-13 G M-05A L P-06A O
J-14A G M-06A O P-07A L
J-15A U M-07 O P-08A L
J-15B G M-08 O P-09L1 L
J-16 G M-10 O P-11 O
J-16A G M-11 O P-12B O
J-17B G M-12A G P-15L1 L
J-18 G M-15 O P-16 O
J-19 G M-16 L P-17 L
J-20A U M-17A L P-18 L
J-20B G M-21A O P-18L1 L
J-21 G M-22 L P-19 O
J-22A G M-23 O P-20B L
J-23 G M-24A O P-21B L
J-24A G M-25 L P-25L1 O
J-25 G M-26A L P-26 O
J-26 G M-31 O Q-01A U
J-27 G M-32 O Q-02A U
J-27A G M-33 O Q-03A U
J-28 G M-34 O Q-05A U
JX-02A G N-01 G Q-06A G
K-01 G N-04A G Q-07A U
K-02C U N-06 L R-04 G
K-03A G N-07 G R-08 L
K-04A O N-09 G R-09A L
K-05B U N-10A L R-12 G
K-06A G N-11B O R-16 O
K-07C O N-12 L R-17A L
K-08 G N-13 U R-18B O
K-09B G N-14A G R-19A L
K-10A G N-15 G R-21 L
K-11 G N-16 G R-23A L
K-12A G N-17 G R-24 O
K-14 O N-18 U R-26A O
K-16A G N-19 G R-27 G
K-16AL2 G N-20A G R-28 O
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code Well Gas Mech Code
R-29A O W-04 U X-14A L Z-06 G
R-30 O W-05 U X-15A L Z-08A U
R-31 O W-06A G X-16 G Z-10 L
R-31A G W-07 L X-17 G Z-11 G
R-35 O W-08 U X-18 L Z-13 G
R-39A L W-08A L X-19B L Z-15 G
R-40 L W-09 U X-21A L Z-16 G
S-01B O W-10A L X-22A L Z-17 U
S-02A L W-11 L X-25 L Z-18 G
S-03 O W-12A L X-27 G Z-21A L
S-05A O W-15 L X-30 L Z-22B L
S-07A L W-15A L X-31 L Z-23A L
S-08B O W-16 L X-31L1 L Z-24 G
S-12A O W-18 L X-32 L Z-25 U
S-16 O W-19A L X-34 L Z-26 G
S-17C L W-20 U X-35 L Z-27 G
S-18A L W-21A L X-35L1 L Z-28 G
S-19 O W-22 O Y-01B O Z-29 U
S-21 O W-23 U Y-02A L Z-30 U
S-23 L W-24 U Y-04 L Z-32B G
S-26 O W-25 U Y-09A L Z-39 L
S-28A L W-26A U Y-13 L
S-29A L W-27 U Y-14B O
S-30 O W-29 U Y-15A O
S-32 O W-30 U Y-16 O
S-33 L W-31 G Y-17B O
S-35 L W-34 G Y-19 O
S-36 L W-35 G Y-20A L
S-37 O W-36 G Y-21A L
S-38 L W-37A G Y-23A O
S-40A O W-38 L Y-25 L
S-41 O W-38A L Y-26A O
S-42 O W-39 G Y-28 O
S-43 L X-01 L Y-29A L
S-44L1 L X-02 G Y-30L1 O
U-02A L X-03A G Y-32L1 O
U-08A O X-04 G Y-33 O
U-09A L X-05 G Y-36 L
U-11B O X-07 L Y-37 O
U-13 L X-08 L Y-37A O
U-14 L X-09B L Y-38 L
U-15B O X-10 L Z-01 G
W-01 U X-12 L Z-03 G
W-02A L X-13A L Z-05 G
Exhibit 7-B
Gas Production Mechanisms
L -GOR below 3050 scf/stb
G -Gas entering perfs from GOC or above
U -Gas entering perfs from an underrun
O -Gas entering perfs from another mechanism (cement channel, Sag River commingling, faults, etc.)
