Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout2001 Endicott Oil Pool
March 29, 2002
Ms. Julie Heusser, Mr. Dan Seamount, Ms. Camille Oechsli Taylor
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave #100
Anchorage, AK 99501-3539
RE: Year End 2001 Endicott Oil Pool - Reservoir Surveillance Report
Dear Commissioners:
Attached is the 2001 annual Endicott Reservoir Surveillance Report. This report is a
compilation of three reports tracking the Key Well Pressure Program, Gas-Oil contact
Monitoring Program, and the Waterflood Surveillance Program.
As in the past, BP Exploration extends an offer to brief the AOGCC regarding the reservoir
depletion status and future plans for the pool. Please advise Jim Ambrose at 564-4375
concerning a convenient time for a meeting or if there are any other questions.
Sincerely,
Mark Weggeland
Endicott Engineering and Development Team Leader
cc: Ambrose, Jim
Kleppin, Daryl
Millholland, Madelyn
Robertson, Daniel
Sauve, Mark / Spearman, Jim
Guitart, Fernando
Working Interest Owners
BP Exploration (Alaska) Inc.
900 East Benson Boulevard
P. O. Box 196612
Anchorage, Alaska 99519-6612
(907) 561-5111
2001 Reservoir Surveillance Report
Endicott Oil Pool
March 31, 2002
Waterflood Surveillance Program
Key Well Pressure Monitoring Program
GOC Monitoring Program
2001 Endicott Reservoir Surveillance Report
Table of Contents Page 1
Waterflood Surveillance Program:
Introduction Page 2
Project Status Summary Page 2
Injection Well Performance Page 2
Waterflood Tracer Page 3
Future Waterflood/EOR Plans Page 3
Figure 1: Endicott Field Well Plat (highlighting injectors) Page 4
Table 1: Summary Of Pertinent Data Page 5
Table 2: Reservoir Balance For Waterflood Sands Page 6
Table 3: Injection Well Data Page 7
Figure 2: Waterflood Tracer Plat Page 8
Pressure Monitoring Program:
Introduction Page 9
2001 Pressure Monitoring Program Page 9
2002 Pressure Monitoring Program Page 10
Figure 3: Endicott Field Well Plat (highlighting Key Wells) Page 11
Table 4: 2001 Key Well Pressure Monitoring Program Page 12
Table 5: 2001 Key Well Pressure Data Page 13
Table 6: 2002 Key Well Pressure Monitoring Program Page 14
GOC Monitoring Program:
Introduction Page 15
2001 Gas-Oil Contact Monitoring Program Page 15
2002 GOC Monitoring Program Page 16
Table 7: Gas-Oil Contact Monitoring Program Page 17
Appendices:
1. Production Rate vs Time Plots
2. Cumulative Crude Production & Percent Recovered vs Time Plots
3. Cumulative Voidage & Reservoir Pressure vs Time Plots
4. Injection Well Rate & Pressure vs Time Plots
5. Endicott Oil Field Historical Key Well Pressure Data
6. Pressure vs Time Endicott Field
1
Endicott Oil Field
2001 Waterflood Surveillance Program
Introduction
Conservation Order 202 Rule 12 approved a field wide waterflood project for the Endicott
reservoir. The waterflood was to be implemented within two years of regular production
and a waterflood plan submitted three months before actual water injection began. By
letter, dated June 15, 1988, the plan to implement the field wide waterflood was approved
and semi-annual pressure maintenance project reports stipulated. The Endicott
Waterflood development was recognized as complete and fully operational by letter, dated
January 11, 1991, and annual waterflood surveillance reporting was approved. This
document constitutes the report for 2001.
Project Status Summary
Endicott Field production began in October 1987. From field start-up, produced gas has
been reinjected back into the existing gas cap to provide pressure support. Water injection
was initiated in February 1988, and a tertiary recovery process was initiated this past year
with the installation of a miscible injection compressor and commencement of miscible
injection in March 1999. This report summarizes the cumulative effects of pressure
maintenance since field start-up and details activities in 2001.
The Endicott Field is generally described as having three areas. The three areas are fault
blocks that are identified as the MPI (Main Production Island area), the SDI (Satellite
Drilling Island area), and the NFB (Niakuk Fault Block). Vertically there are six subzones
(3C, 3B, 3A, 2B, 2A, 1) that are the general geological subdivisions within the Kekiktuk
formation.
Initially produced gas was reinjected into the gas cap in the updip portion of MPI subzones
2A and 2B. Gas injection was extended into the MPI subzone 3A gas cap in May 1988,
and into the subzone 3C gas cap in both the MPI and the SDI areas in 1993. Reservoir
studies subsequently identified the SDI 3C area as a primary EOR target and supported
the decision to halt immiscible gas injection in that subzone. As a result, SDI 3C gas
injector 1-15/P-25 was shut-in July 1998. In October 2000 well 1-15/P-25 was placed back
on production when gas injector 2-06/J-22 was shut in with annular communication. Well
1-15/P-25 was shut in during July 2001 upon completion of a workover to return 2-06/J-22
to gas injection.
2
Water injection is occurring in peripherally placed injectors in all subzones in all areas of
the field with the exception of Zone 1, which is on primary depletion.
Endicott’s EOR project began in March of 1999. The original EOR Phase I implementation
plan consisted of 8 water-alternating-gas (WAG) injection wells, with two wells being on MI
at any given time. This plan was based on an MI compressor design rate of 45 mmscfpd.
In reality, the maximum sustainable MI rate achieved by the compressor has been closer to
20 mmscfpd, which can be handled by one well at a time. As a result, miscible gas
injection has primarily been alternated between NFB 3A injector 2-22/L-14 and SDI 3C
injector 4-04/T-26. Produced gas samples have been collected in all of the producers
offset from these injection wells to provide a baseline for use in MI breakthrough
monitoring.
Figure 1 shows a map of the field with current well statuses including the existing water
injectors, gas injectors and oil producers. No well service additions or changes have
occurred since the last report date.
Table 1 summarizes total production, injection, and well count data for the entire pool
through December 2001. Table 2 details the reservoir balances by area and subzone
through December 2001. The NFB is included in with the MPI on Table 2 for simplicity.
Appendix 1 provides graphs of Production and Gas/Oil Ratio versus Time by area and
subzone.
Appendix 2 provides graphs of Cumulative Crude Production and Percent Original Oil in
Place (OOIP) Recovered versus Time by area and subzone.
Appendix 3 provides graphs of Cumulative Voidage and Reservoir Pressure versus Time
by area and subzone.
Injection Well Performance
Table 3 provides an overview of the performance of each of the pressure maintenance
injectors. Included in this exhibit are the start-up dates, cumulative injection volumes, and
current target injection rates.
Appendix 4 provides graphs of the injection rates, injectivity index, and wellhead pressure
3
versus time for each of the active injectors.
Waterflood Tracer
The waterflood tracer program was started in 1988. A total of 19 water injectors have been
traced: 3 in 1988, 8 in 1989, 6 in 1991, and 3 in 1996 (well 2-44/R-12 was traced with two
different tracers). The program has been very successful in identifying the progress of the
waterflood as depletion matures. Numerous interventions have been implemented on
producers and injectors to improve ultimate recovery.
Figure 2 is an Endicott well plat showing the dates and types of tracers injected and the
producing locations where the tracer has appeared.
Future Waterflood/EOR Plans
In 2002 there are no plans to trace additional water injectors. Twelve wells will be
monitored for tracer. Samples of produced gas will continue to be obtained in the
production wells that offset the EOR injection wells to monitor MI movement. Average MI
injection rate in 2001 was 14.2 mmscfpd, the highest annual average rate in the project life.
Reservoir pressure and gas and water movement will continue to be closely monitored
through logging, mechanical isolations, and well testing. Changing pressure maintenance
needs will continue to be met by evaluating new well drilling locations, converting
producers to injectors, profile modification of existing injectors, and target injection rate
control. Offtake will continue to be optimized by evaluating new well drilling locations,
remedial work on existing producers, and production rate control.
DUCK
ISLAND
ANXIETY
POINT
HOWE
ISLAND
ENDEAVOR
ISLAND
SAG
DELTA 2/2A
MPI
SDI
DUCK IS.
1 & 2
SAG DELTA
3 & 4
RESOLUTION
ISLAND
DUCK IS. 3
ISLAND
Y0191
5
12
15
10
3
34
27
22
14
11
2
35
26
23
13
12
1
36
25
24
18
7
6
31
30
19
17
8
5
32
29
16
9
4
33
15
10
3
11
2
G
W
G
W
W
W
W
W
W
W
G
G
W
WWW
W
W
W
W
W
W
W
W
W
W
W
W
W
W
W
W
G
W
W
DATE:SCALE:
BP EXPLORATION (ALASKA) INC.
4000bord.dgn
1" = 4000'
ENDICOTT FIELD
OIL PRODUCER
WATER INJECTOR
GAS INJECTOR
CRETACEOUS DISPOSAL
DRILLED (DARKER COLOR)
PROPOSED (LIGHTER COLOR)
LEGEND - WELLTYPE MAP
ENDICOTT FIELD
SUBZONES: PRIMARY/SECONDARY
SOLID
DASHED
W
G
SUBZONE 3C
SUBZONE 3B
SUBZONE 3A
SUBZONE 2B
SUBZONE 2A
P3
FAULTS
TOP SADLEROCHIT
SUBZONE 1
3/17/2002FIGURE 1
WELL STATUS
J-19
1-01
2A
P-16
1-03
2B
O-20
1-05
3A
J-18
1-09
L-21
1-09A
1
SN-04
1-11
TSAD
P-25
1-15
3C/3B
SN-02
1-17
TSAD
I-17
1-17A
3A
I-18
1-19
2B
K-25
1-21
2A/1
O-15
1-23
2A
N-22
1-25
K-22
1-25A
1
K-22
1-25A
P-20
1-27
2A
M-25
1-29
2A
M-21
1-31
2A
M-23
1-33
2A
L-24
1-33B
2A
O-25
1-35
3A
P-24
1-37
3A
P-17
1-39
3A/3B
O-23
1-41
2B/2A
P-26
1-43
3B/3A/2B
Q-26
1-45
3B
Q-21
1-47
M-20
1-47A
2A/1
P-21
1-49
3A
V-20
1-51
3C/3B
Q-20
1-53
R-25
1-55
3C
R-23
1-57
3C
O-24
1-59
2B
Q-20
1-61
2B Q-20
1-61
T-22
1-63
3C/3B
N-25
1-65
2B
N-25
1-65
T-20
1-67
3CV-19
1-69
3C/3B
P-18
2-02
M-19
2-04
2A J-22
2-06
2A
K-16
2-08
3A
Q-16
2-12
3C
O-16
2-14
2A
M-16
2-16
2B/2AL-16
2-18
3A/3B
L-15
2-20
3C
L-14
2-22
3B/3A
M-12
2-24
3C/3B
N-14
2-26
3C/3B
P-19
2-28
3A/2B
O-09
2-30
3C
EI-02
SN-03
2-32
TSAD
P-14
2-34
2B/2A
O-14
2-36
3A
SN-01
2-38
TSAD
S-22
2-40
3C/3B
P-13
2-42
3BR-12
2-44
3C/3B/3A
Q-11
2-44A
3C
Q-15
2-46
3B
R-10
2-46A
3C
S-13
2-46B
3C
O-13
2-48
3A
U-08
2-50
3C
S-14
2-52
3C/3B
Q-12
2-54
3A
S-09
2-58
3C
U-13
2-60
3C
Q-17
2-62
3C/3B
U-10
2-64
3C
SD-12
2-66
2A
S-17
2-68
3C/3BU-15
2-70
3C/3B
N-29
3-01
3A
J-33
3-03
2A
O-29
3-05
3B
N-28
3-07
2A
L-29
3-07A
2A
L-28
3-09
2A
L-28
3-09
L-28A
3-09
2B
M-30
3-11
3A/2B
K-33
3-15
2B
K-33
3-15
J-30
3-17J-30A
3-17
M-31
3-17D
3A
R-28
3-19
3C/3B
L-34
3-21
3AN-32
3-23
3B
M-27
3-25
2A
M-33
3-27
3B/3A/2B
J-32
3-29
2B/3A
K-32
3-31
2B
K-37
3-33
2B
L-36
3-35
3A
L-35
3-37
2A J-39
3-39
I-37
3-39A
2A
K-39
3-41
2B/2A
P-36
3-43
3C
M-39
3-45
3B/3A/2B
Q-35
3-47
3C/3B
J-40
3-49
M-40
3-49A
3B
Q-28
4-02
3C
T-26
4-04
3C Q-32
4-06
Q-30
4-06A
3C
P-27
4-08
3A/2B
M-28
4-10
2A
R-34
4-14
3C/3B
S-30
4-18
3C
M-35
4-20
3B
T-34
4-20
O-34
4-26
3B/3A N-37
4-28
3C/3B
K-38
4-32
3A
O-38
4-34
3C
K-34
4-38
2A/2B
P-43
4-40
3C
P-38
4-42
3C M-44
4-44
3C
N-39
4-46
3C/3B K-43
4-48
3B/3A
K-41
4-50
3B/3A
SD-07
5-01
2B/2A
SD-10
5-02
2A
SD-09
5-03
TSAD
DI-01
DI-01
DI-02
DI-02
DI-03
DI-03
SD-03
SD-03
SD-04
SD-04
SD-08
SD-08
4
TABLE 1
ENDICOTT OIL POOL
SUMMARY OF PERTINENT DATA
(as of December 31, 2001)
Water Injection Start-up: February 29, 1988
Miscible Gas Injection Start-up: March 24, 1999
Endicott Production since Field Start-Up:
Black Oil and Condensate (MMSTB) 402.3
NGL's (MMSTB) 17.0
Gas (BSCF) 1,417.4
Water (MMB) 511.2
Endicott Injection since Field Start-Up:
Gas (BSCF) 1,240.5
Miscible Injectant (BSCF) 9.7
Water (MMB) 871.4*
Wells in Operation:
Oil Producers 47
Gas Injectors 4
Water Injectors 21
Water-Alternating-Gas Injectors 1
Waste Water Disposal 1 **
Total 74
* Water injection volumes do not include Cretaceous injection
** Cretaceous injector not shown in Exhibit 1
5
MPI REGION by SUBZONE
Produced Volume 3C 3B 3A 2B 2A 1 MPI TOTAL
Oil 24.36 9.17 59.76 74.56 143.65 3.62 315.12
Free Gas 43.17 11.71 116.38 128.60 260.60 4.72 565.18
Water 13.71 5.46 68.98 80.59 90.48 1.06 260.29
Total 81.25 26.35 245.12 283.74 494.73 9.41 1,140.59
Injected Volumes
Gas 94.83 0.00 207.74 184.79 297.18 0.00 784.54
MI 16.83 5.72 75.88 74.38 96.19 0.00 268.99
Water 0.00 0.07 3.32 0.00 0.00 0.00 3.39
Total 111.66 5.79 286.94 259.17 393.36 0.00 1,056.92
Net Voidage Volumes
Total -30.41 20.56 -41.81 24.56 101.36 9.41 83.67
SDI REGION by SUBZONE
Produced Volume 3C 3B 3A 2B 2A 1 SDI TOTAL
Oil 50.74 16.42 32.32 87.20 41.50 0.04 228.22
Free Gas 84.06 16.22 7.00 37.75 48.51 0.09 193.62
Water 54.40 17.80 35.94 115.91 42.17 0.02 266.24
Total 189.21 50.44 75.26 240.86 132.17 0.15 688.08
Injected Volumes
Gas 66.00 2.95 0.00 0.00 0.00 0.00 68.95
MI 59.87 29.57 36.32 148.18 52.34 0.00 326.29
Water 6.58 0.04 0.00 0.00 0.00 0.00 6.63
Total 132.45 32.56 36.32 148.18 52.34 0.00 401.86
Net Voidage Volumes
Total 56.75 17.87 38.94 92.68 79.83 0.15 286.22
FIELD TOTALS by SUBZONE
3C 3B 3A 2B 2A 1 FIELD TOTAL
Produced Volume
Oil 75.10 25.59 92.08 161.76 185.15 3.66 543.34
Free Gas 127.23 27.93 123.38 166.34 309.11 4.81 758.80
Water 68.11 23.26 104.92 196.49 132.65 1.08 526.52
Total 270.45 76.78 320.39 524.59 626.90 9.55 1,828.67
Injected Volumes
Gas 160.83 2.95 207.74 184.79 297.18 0.00 853.49
MI 76.70 35.29 112.20 222.56 148.53 0.00 595.28
Water 6.58 0.11 3.32 0.00 0.00 0.00 10.01
Total 244.11 38.35 323.26 407.35 445.71 0.00 1,458.78
Net Voidage Volumes
Total 26.34 38.43 -2.87 117.24 181.19 9.55 369.88
NOTE: Water injection volumes do not include Cretaceous injection
TABLE 2
ENDICOTT OIL POOL
RESERVOIR BALANCE FOR WATERFLOOD SANDS
Through12/31/2001
(Values in MMRB)
6
MPI Reservoir Area
Water Gas Cumulative Cumulative Cumulative
Target Target Water Gas MI Start-Up
Well Name MBWPD MMSCFGPD MMBW BSCFG BSCFG Date
1-05/O-20 100 304.02 May-88
1-23/O-15 18 43.43 Mar-95
1-37/P-24 0 23.11 Dec-87
1-41/O-23 15 31.66 Dec-95
2-06/J-22 110 378.44 Oct-87
2-12/Q-16 80 138.79 Apr-93
2-16/M-16 20 56.55 Mar-89
2-22/L-14 17 0.00 (MI) 38.54 3.29 May-89
2-24/M-12 4 3.80 Mar-95
2-34/P-14 16 52.32 Nov-89
*2-44/R-12 0 20.78 Mar-89
2-54/Q-12 20 55.13 Jan-92
2-64/U-10 3 3.30 Dec-90
2-70/U-15 5 17.67 Jul-89
5-01/SD-07 110 326.91 Oct-87
5-02/SD-10 10 47.39 Jan-88
88.37
SDI Reservoir Area
Water Gas Cumulative Cumulative Cumulative
Target Target Water Gas MI Start-Up
Well Name MBWPD MMSCFGPD MMBW BSCFG BSCFG Date
1-15/P-25 0 100.90 Jun-93
1-43/P-26 30 102.99 Apr-89
1-51/V-20 3 8.64 Apr-93
1-67/T-20 11 9.31 May-99
1-69/V-19 3 14.26 Dec-90
**3-07/N-28 0 47.61 Apr-89
3-37/L-35 13 15.08 Aug-98
3-41/K-39 22 94.22 Apr-89
3-45/M-39 14 40.95 Sep-88
3-47/Q-35 6 13.63 0.08 Mar-95
3-49A/M-40 6 3.85 Apr-99
+ 4-02/Q-28 0 8.48 May-88
4-04/T-26 10 20.00 (MI) 26.87 6.36 Mar-90
4-08/P-27 14 34.60 May-93
4-14/R-34 0 38.10 Oct-89
4-40/P-43 0 7.09 Oct-92
++ 4-48/K-43 0 11.85 Dec-90
Total 260 400 871.19 1337.43 9.72
Note: Water injection volumes do not include Cretaceous injection.
* Sidetracked in 9/97
** Converted to production in 8/98
+ Converted to production in 4/96
++ SI since 4/97
Table 3
Endicott Oil Pool
Injection Well Data
Through 12/31/2001
DI-03
DI-02
DI-01
SAG-03
SD-08
1-33
M-231-49
P-21
1-31
M-21
1-45
Q-261-55
R-25
1-57
R-231-67
T-20
3-17
J-30A
3-03
J-33
3-21
L-34 3-37
L-35
3-35
L-364-26
O-34
4-32
K-38
4-38
K-34
3-39
J-39
2-20
L-15
2-68
S-17
2-26
N-14
3-33
K-37
4-42
P-38
4-46
N-394-34
O-38
4-18
S-30
3-43
P-36
4-06A
Q-30
3-23
N-32
3-27
M-33
P-43
M-44
K-43
R-34
M-39
K-39
W
W
W
W
W
W
W
3-09
L-28A
1-21
K-25
3-29
J-32
4-02
Q-283-19
R-28
1-35
O-25
SD07
P-26P-25
T-26
P-24
O-24 SD-10
J-22
1-63
T-22
2-40
S-22
1-47
Q-21
V-20
U-10
SD12 V-19
U-15
2-60
U-13
2-46A
R-10 2-52
S-14
2-62
Q-17
2-58
S-09
1-25
N-22
2-28
P-19
1-61
Q-20
1-27
P-20
O-20
W
W
W
W
G
W W W
2-50
U-08
W
W
Q-12
W
SD-04
2-42
P-13 2-04
M-19
2-36
O-14
O-09
W
M-12
W L-14
W
M-16
W
1-17A
I-17
2-32
SN-03
1-01
J-19
2-08
K-16
SD09
SD04
W
W
G
G
2-38
SN-01
1-19
I-18
G
W
W
O-15
Q-16 1-39
P-17
1-03
P-162-48
O-13
G
W
W
T-34
T-31
J-30
L-28
SN02
P-18
1-53
Q-20
2-18
L-16
3-49
J-404-50
K-41
Q-35
1-09
J-18
ENDICOTT FIELD
WW AA TT EE RR FF LL OO OO DD TT RR AA CC EE RR PP RR OO GG RR AA MM
1988 Program
Well Tracer
1-37/P-24 Colbalt-60
4-02/Q-28 Carbon-14/SCN
5-02/SD-10 Tritium
1989 Program
Well Tracer
2-16/M-16 Carbon-14/SCN
2-22/L-14 Cobalt-60
2-44/R-12 Tritium
2-70/U-15 Colbalt-60
3-07/N-28 Colbalt-57
3-41/K-39 Tritium
3-45/M-39 Colbalt-60
4-14/R-34 Carbon-14/SCN
1996 Program
Well Tracer
1-23/O-15 Sodium 22
4-08/P-27 Carbon-14/IPA
4-40/P-43 Potassium Hexacyanacobalte
Ammonium
Thiocynanate (SCN)
Sodium Benzoate (P-14)
Potassium Hexacyanocobaltate
Carbon-14/IPA
Tritium
Colbalt-57
Mg & SO4
Sodium 22
Carbon-14/SCN
Colbalt 60
M.Millholland 2/29/00
FIGURE 2
1991 Program
Well Tracer
1-69/V-19 Carbon-14/SCN
4-04/T-26 Tritium
4-48/K-43 Carbon 14/SCN
1-43/P-26 Ammonium Thiocyanate (SCN)
2-34/P-14 Ammonium Thiocyanate (SCN)
2-44/R-12 Sodium Benzoate
TRACER TYPES
4-10
M-28
1-09A
L-21
P-14
R-12
4-20
M-35
3-05
O-29
3-25
M-27
1-29
M-25
1-65
N-25
P-27
MPI
SDI
Q-15
O-23
3-11
M-30W
N-28 3-01
N-29
4-28
N-37
2-14
O-16
Q-32
PROD WELL
INJ/PREVIOUS PROD
INJ WELL
P&A WELL
3-15
K-33
TI
G
V
A
R
I
A
K
F
A
U
L
T
MI
K
K
E
L
S
E
N
B
A
Y
F
A
U
L
T
NIAKUK FAULT
MIDFIELD FAULT
7
Endicott Oil Field
2001 Pressure Monitoring Key Well Program
Introduction
A pressure monitoring key well program was submitted to and approved by the AOGCC in
Administrative Approval No. 202.5. This program supersedes the requirements of
Conservation Order 202, Rule 6(c), and complies with Conservation Order 202, Rule 6(d).
The pressure monitoring program key wells were chosen to provide a real coverage of
reservoir pressure in each of the major subzones in the two production areas of the
reservoir. Historically, the Key Well Program has included at least two points of pressure
measurement for each of the producing subzones, one from each MPI and SDI area, to
ensure that a valid picture of reservoir pressure behavior can be drawn.
Seventeen wells were identified as key wells to track pressure variation within the five
major subzones in each of the two main producing areas of the reservoir. Changes have
been made through time as reservoir and well characteristics changed in order to provide
representative data. Much more reservoir pressure data, other than the key well data, is
gathered to address specific well and reservoir surveillance needs.
Figure 3 is an Endicott well plot showing the location of the seventeen 2001 Key Well
reservoir pressures.
2001 Pressure Monitoring Program
Table 4 summarizes the wells included in the Proposed 2001 Key Well Program. The
2001 program consisted of seventeen key wells. Table 5 summarizes the key well
pressure data gathered in 2001. The zone 1 pressure was observed in Well 1-09A/L-21
rather than the proposed well 1-25/K-22 due to operational concerns.
Appendix 5 lists, by subzone, all current and former key wells with the reservoir pressures
obtained since field start-up. These pressures are adjusted to a datum depth of 10,000
feet TVDSS, as is customary in our state pressure reporting.
Appendix 6 plots, by subzone and area, key well reservoir pressures along with all other
reservoir pressure surveys. Generally speaking there is good agreement between the key
8
well reservoir pressures and other pressure gathered around the field. There are a few
exceptions where wells are in small pressure isolated regions.
2002 Pressure Monitoring Program
The Endicott Key Well Pressure Monitoring Program has been successful in establishing
and monitoring pressure trends within each of the major subzones. Changes in well
service and configuration occasionally necessitate changes to the pressure monitoring
program in order to obtain representative data, BPX recommends changing the MPI 2B
monitoring location towel 1-03/P-16 from 1-61/Q-20 in the 2002 program.
Table 6 summarizes the 2002 Endicott key well pressure monitoring program proposal.
As in past years, the amount of static pressure data obtained annually will likely exceed the
seventeen wells included in the proposed 2002 Key Well Pressure Monitoring Program. At
the operator’s discretion, representative reservoir pressures gathered in other wells during
2002 might be substituted for the proposed key wells to minimize production impacts or for
operational necessity. As the field matures, we will be increasingly challenged with
managing this need for additional pressure data while minimizing the cost and associated
production impacts.
DUCK
ISLAND
ANXIETY
POINT
HOWE
ISLAND
ENDEAVOR
ISLAND
SAG
DELTA 2/2A
MPI
SDI
DUCK IS.
1 & 2
SAG DELTA
3 & 4
RESOLUTION
ISLAND
DUCK IS. 3
ISLAND
Y0191
G
W
G
W
W
W
W
5
12
W
W
G
G
W
WWW
W
W
W
W
W
W
W
W
15
10
3
34
27
22
W
14
11
2
35
26
23
13
12
1
36
25
24
18
7
6
31
30
19
17
8
5
32
29
16
9
4
33
15
10
3
11
2
W
W
W
W
W
W
G
W
W
G
W
G
W
W
W
W
W
W
W
G
G
W
WWW
W
W
W
W
W
W
W
W
W
W
W
W
W
W
W
W
G
W
W
DATE:SCALE:
BP EXPLORATION (ALASKA) INC.
4000bord.dgn
1" = 4000'3/17/02
ENDICOTT FIELD
2001 KEY WELL
RESERVOIR PRESSURE DATA
FIGURE 3
1-01/J-192-18/L-16
2-26/N-14
1-61/Q-20
1-39/P-17
2-42/P-13
2-52/S-14
2-58/S-09
3-39A/I-37
4-32/K-38
3-35/L-36
3-23/N-32
4-18/S-30
1-57/R-23
40983903
6137
4502
5282
5277
2615
4270
4458
46365161
4900
4644
4636
3-33/K-37
1-33B/L-24
4212
4766 1-47A/M-20
4194
1-29/M-25
4079 3-25/M-27
4302
3-17D/M-31
4341
2-44A/Q-11
5010
1-25/K-22
2698
1-03/P-16
4497
1-35/O-25
4563
1-19/I-18
4257
2-06/J-22
4200
2-50/U-08
3210
2-22/L-14
4334
4-38/K-34
4230
OIL PRODUCER
WATER INJECTOR
GAS INJECTOR
CRETACEOUS DISPOSAL
DRILLED (DARKER COLOR)
PROPOSED (LIGHTER COLOR)
LEGEND - WELLTYPE MAP
ENDICOTT FIELD
SUBZONES: PRIMARY/SECONDARY
SOLID
DASHED
W
G
SUBZONE 3C
SUBZONE 3B
SUBZONE 3A
SUBZONE 2B
SUBZONE 2A
P3
FAULTS
TOP SADLEROCHIT
SUBZONE 1
9
Well Area Subzone(s)Comments
1-25A/K-22 MPI Z1
1-01/J-19 Niakuk 2A
2-18/L-16 Niakuk 3A
2-26/N-14 Niakuk 3B/3C Commingled pressure
1-33B/L-24 MPI 2A
1-61/Q-20 MPI 2B Single zone high angle well
1-39/P-17 MPI 3A Lower 3A monitor point
2-42/P-13 MPI 3B
2-52/S-14 MPI 3B/3C Commingled pressure
2-58/S-09 MPI 3C
3-39A/I-37 SDI 2A
3-33/K-37 SDI 2B
3-35/L-36 SDI 3A Upper 3A monitor point
4-32/K-38 SDI 3A Lower 3A monitor point
3-23/N-32 SDI 3B
4-18/S-30 SDI 3C Eastern area
1-57/R-23 SDI 3C Western area
2001 KEY WELL PRESSURE MONITORING PROGRAM PROPOSAL
ENDICOTT FIELD
TABLE 4
10
Well Area Subzone(s)Pressures
1-25A/K-22 MPI Z1 2698 psia
1-01/J-19 Niakuk 2A/2B 4098 psia
2-18/L-16 Niakuk 3A 3909 psia
2-26/N-14 Niakuk 3B/3C 6137 psia
1-33B/L-24 MPI 2A 4212 psia
1-61/Q-20 MPI 2B 4502 psia
1-39/P-17 MPI 3A 4766 psia
2-42/P-13 MPI 3B 5282 psia
2-52/S-14 MPI 3B/3C 5277 psia
2-58/S-09 MPI 3C 2615 psia
3-39A/I-37 SDI 2A 4458 psia
3-33/K-37 SDI 2B 4636 psia
3-35/L-36 SDI 3A 5161 psia
4-32/K-38 SDI 3A 4636 psia
3-23/N-32 SDI 3B 4900 psia
4-18/S-30 SDI 3C 4644 psia
1-57/R-23 SDI 3C 5019 psia
DATUM: 10000' TVDss
2001 KEY WELL PRESURE MONITORING PROGRAM DATA
ENDICOTT OIL FIELD
TABLE 5
11
Well Area Subzone(s)Comments
1-25A/K-22 MPI Z1
1-01/J-19 Niakuk 2A/2B Commingled pressure
2-18/L-16 Niakuk 3A
2-26/N-14 Niakuk 3B/3C Commingled pressure
1-33B/L-24 MPI 2A
1-03/P-16 MPI 2B Single zone high angle well
1-39/P-17 MPI 3A Lower 3A monitor point
2-42/P-13 MPI 3B
2-52/S-14 MPI 3B/3C Commingled pressure
2-58/S-09 MPI 3C
3-39A/I-37 SDI 2A
3-33/K-37 SDI 2B
3-35/L-36 SDI 3A Upper 3A monitor point
4-32/K-38 SDI 3A Lower 3A monitor point
3-23/N-32 SDI 3B
4-18/S-30 SDI 3C Eastern area
1-57/R-23 SDI 3C Western area
Change from the 2001 proposed program:
Substituted 1-03/P-16 for 1-61/Q-20 in MPI 2B
2002 KEY WELL PRESSURE MONITORING PROGRAM PROPOSAL
ENDICOTT FIELD
TABLE 6
12
Endicott Oil Field
2001 GOC Monitoring Program
Introduction
A Gas - Oil Contact (GOC) Monitoring Key Well Program was submitted for the Endicott
Field in October 1988, one year after field start-up in accordance with AOGCC
Conservation Order 202, 9(c). At that time, BP Exploration sought, and received a waiver
(Administrative Approval Order 202.5) from the State of Alaska, to initiate the key well
program for Endicott on a subzone basis for each of the three distinct reservoir
development areas of the field. Administrative Order No. 232.1 provided an exemption for
key well GOC monitoring in Sections 1, 3, 7, 9, 10, and 35 of the field as being outside a
real gas cap limits of the reservoir.
The initial GOC Monitoring Key Well Program consisted of six wells: 1-01/J-19, 1-09/J-18,
1-27/P-20, 1-29/M-25, 2-04/M-19, 3-01/N-29. Table 7 details the history of pulsed neutron
log observations in the six GOC key wells. The table identifies GOC movement and gas
influx by under-running major shales within Subzones 3A and 2B.
Conservation Order No. 462, rule 9 (b) revoked the Key Well Monitoring Program and
allowed the operator to submit modifications to the Gas Oil Monitoring Program for
Commission approval. The details of the 2002 GOC Monitoring Program as submitted by
the operator are listed in the section below.
The GOC monitoring program for Endicott is based on the understanding of a limited ability
to monitor field-wide gas cap movement. A scarcity of wells and limited lateral offset from
gas severely restricts the use of time lapse cased-hole logging as a viable tool to predict
gas movements at Endicott. It is recognized that narrow hydrocarbon corridors caused by
a relatively steep 6 degree structural dip combined with sands separated by thick laterally
continuous shales promotes under-running as a common gas movement mechanism. In
addition to the continuous shales that separate the reservoir into six vertically isolated
subzones, major east-west trending fault offsets provide either lateral hydraulic isolation or
partial pressure communication between the three main Endicott development areas.
The more massive high quality sands of the 3A and 2B subzones are where more regional
GOC effects are more easily noted. Monitoring region gas movement in the 2A subzone is
more tenuous due to the close proximity to gas and likelihood of localized gas coning and
under runs. Monitoring gas movement in the 3B, and 3C subzones is not practical due to
13
complex stratigraphy (shaliness).
2001 GOC Monitoring Program
During 2001, a total of four cased - hole pulsed and compensated neutron logs (PNL /
CNL) were acquired. These logs are routinely used for reservoir surveillance and
diagnosing well problems in order to develop reservoir management plans and remedial
interventions. Following is a list of the wells from which neutron logs were acquired during
2001:
Well Location Well Location
2-14/O-16 MPI 3-39A/I-37 SDI
2-28/P-19 MPI 4-38/K-32 SDI
4 Wells Total
The 2001 GOC monitoring program focused on the understanding the location of gas in the
2A, 2B and 3A subzones in the northwest area of the MPI fault block (2-14/O-16, 2-28/P-
19) and the 2A subzone near the eastern truncation in the SDI fault block (3-39A/I-37, 4-
38/K-32).
2002 GOC Monitoring Program
BPX proposes a 2002 GOC Monitoring Program consist of a notional five well program that
focuses on the 2B intervals in the reservoir. Gas movement in these intervals is the most
active. These intervals have the highest potential for monitoring depletion and improving
recovery through effective reservoir management and the identification of potential infill drill
locations.
Production logging and down-hole mechanical isolation of gas prone intervals also provide
a means to monitor gas influx. Together, these tools constitute an effective means to
monitor gas movement at Endicott.
14 Table 7ENDICOTT OIL POOLGAS OIL CONTACT MONITORING PROGRAMSTATUS REPORT- 12/31/2001NIAKUK FAULT BLOCK MPIWELL 1-01/J-19 1-09/J-18 1-27/P-20 1-29/M-25 2-04/M-19GOC SUBZONE2B 3A 3A 2B 2BDATE OF BASELINE31-Jan-89 11-Jan-88 29-Feb-88 3-Feb-88 1-Mar-88MONITOR SURVEYS12-Jan-90 14-Jan-88 21-Feb-87 3-Feb-88 1-Mar-88NM, GUR (2A) NM NM (OHCNL) GCX (13') GCX (25')213-Feb-91 1-Feb-89 9-May-88 8-Aug-88 20-Mar-89NM, GUR (2A) GCX (4'),GUR(2B5) NM GCX (33') GCX(35'), GUR (2B2)331-Jan-91 14-Feb-90 4-Aug-88 6-Aug-89 16-Jun-90NM, GUR (2A) GCX (10'), GUR(2B5) NM, GUR (2B3) GCX (43') GCX(4'), GUR (2A3)429-Mar-93 24-Feb-91 12-Apr-89 5-Sep-90 29-Jun-91NM, GUR (2A) GCX (7'), GUR (2B5) NM,GUR (2B3) GCX (48') GCX (NM), GUR (2A3)528-Jul-94 16-Mar-92 17-Jun-90 25-Mar-91 14-Jun-92NM, GUR (2A) GCX (5'), GUR (2B5) GCX(9'), GUR (2B3) GCX (53') GCX (2'), GUR (2A3)624-Jun-95 22-Aug-93 4-Jul-91 17-Mar-92 25-Jun-93NM , GUR (2A) GCX(2'), GUR(2B5) GCX (14'), GUR (2B3 / 3A2) GCX (72') NM, GUR (2A3)718-Jul-96 30-Jul-94 13-Jun-92 24-May-93 9-Jul-94GCX (-30' in 2B), GUR (2A) NM, GUR (2B5) GCX (23'), GUR (2B3/3A2) GCX(92'), GUR(2A3) NM, GUR (2A3)810-Aug-97 Waiver-No Monitor Logs 26-Jun-93 29-Jul-94 *11-Aug-97GCX (-30' in 2B), GUR (2A) Well sidetracked to new location GCX(28'), GUR(3A2) GCX (97'), GUR (2A3) GCX (18' in 2B), GUR (2A3)927-Sep-98 31-Jul-94 26-Jun-95 Waiver-No Monitor LogsGCX (-30' in 2B), GUR (2A) GCX (30'), GUR (2B3) GCX (97'), GUR (2A3)1013-Mar-99 27-Mar-95 18-Jul-96GCX (-30' in 2B), GUR (2A) GCX (30'), GUR (2B3) GCX (97'), GUR (2A3)1116-Aug-00 19-Jul-96 1-Aug-97GCX (-30' in 2B), GUR (2A)GCX (31'), GUR (2B3)GCX (95' ), GUR (2A3)1213-Jul-97 25-Sep-98GCX (31'), GUR (2B3)GCX (94'), GUR (2A3)1325-Sep-98 12-Mar-99GCX (30'), GUR (2B3)GCX (94'), GUR (2A3)1412-Mar-99 14-Aug-00GCX (30'), GUR (2B3)GCX (90'), GUR (2A3)1510-Jun-00GCX (30'), GUR (2B3)NM = NO GAS CAP MOVEMENT * Note: obtained neutron log for reservoir survellaince for infill drilling programGUR = GAS UNDERRUN (STRAT. SEQ.)GCX = GAS CAP EXPANSION (FEET TVD)
Appendix 1
Appendix 2
Appendix 3
Appendix 4
Appendix 5
Appendix 6
