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Annual Reservoir Surveillance Report
Nikaitchuq Schrader Bluff Oil Pool (NSBOP)
Nikaitchuq Field
April 1, 2022
Table of Contents
SUBJECT
1.0 Progress of the Enhanced Recovery Project................................................................................1
2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool...........................................4
3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys,
Observation Well Surveys and Any Other Special Monitoring..................................................... 5
4.0 Review of Pool Production Allocation Factors and Issues Over the Year ..................................... 7
5.0 Reservoir Management Summary.............................................................................................. 8
ATTACHMENT A: NSBOP Well Location Map.............................................................................................10
ATTACHMENT B: 2020 NSBOP Voidage Balance by Month.......................................................................11
ATTACHMENT C: NSBOP Pressure Reports, Form 10-412..........................................................................12
ATTACHMENT D: NSBOP Reservoir Pressure Map — December, 2020.......................................................15
ATTACHMENT E: NSBOP Annual Reservoir Properties Report, Form 10-428.............................................16
ATTACHMENT F: NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) .............................17
Eni Petroleum —Alaska Development
1.0 Progress of the Enhanced Recovery Project
The Nikaitchuq Field (NF) is one of two Eni US Operating Co. Inc. (Eni) offshore -operated fields in
Alaska. It is located offshore in East Harrison Bay, near the Colville River Delta in the Beaufort
Sea. The Nikaitchuq Schrader Bluff Oil Pool (NSBOP) development utilizes an onshore gravel pad
located at the Oliktok Point Pad (OPP) and the offshore Spy Island Drill site (SID). The onshore
development contains standalone multiphase processing facilities. SID is a drilling location from
which offshore production is imported via a flowline bundle to OPP. Processed oil sales are
exported through a dedicated pipeline tied -in to the Kuparuk River Unit (KRU) facilities, operated
by ConocoPhillips Alaska, Inc. (CPAI), which exports the oil to the Trans -Alaska Pipeline System
(TAPS). The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under
Conservation Order No. 639 (CO 639) and Area Injection Order 36 (AIO 36) authorizing the
injection of fluids for pressure maintenance and enhanced oil recovery in the NSBOP.
At the end of 2021, there were 54 active NSBOP development wells, including 31 production (11
OPP, 20 SID) and 23 injection (8 OPP, 15 SID) wells. Dual lateral wellbores have been completed
in 22 of the production wellbores (8 OPP, 14 SID). These wells target the OA sand of the NSBOP.
One inactive development well, OP19-TIN, was drilled and completed to test the potential of the
N sand development. Additionally, two disposal wells (1 OPP, 1 SID) and three Ivishak source
water wells (3 OPP) are active in supporting operations. Future development plans include drilling
four additional OA wells and recompleting OP19-T1N to further assess the N sand development
potential. Under the current economic environment, this scenario will be completed in 2025, but
it is subject to change. The existing and planned NSBOP wells are shown in Attachment A.
In 2021, Eni continued rig activities at both OPP and SID. In total, 30 rig activities (8 OPP, 22 SID)
including 22 workovers (8 OPP, 14 SID) and 8 SID drilling operations were conducted in 25 wells
(7 OPP, 18 SID) including the SD37-DSP01 disposal well and the OP26-DSP02 disposal well as
summarized in Table 1 below.
Eni Petroleum —Alaska Development Page 1
Well Name
Well Type
Site
Activity
Rig Name
Start Date
Completion Date
Description
0113-03
Injector
OPP
Rigless
25-Mar-21
2-May-21
Tubing leak diagnostics
0115-S4
Injector
OPP
Rigless
24-Mar-21
4-Jun-21
Tubing leak diagnostics
0120-07
Injector
OPP
Rigless
28-Mar-21
5-Jun-21
Tubing leak diagnostics
0106-05
Injector
OPP
Rigless
28-Mar-21
7-Jul-21
Tubing leak diagnostics
OP09-Sl
Producer
OPP
Rigless
11-Sep-21
14-Sep-21
SOV replacement
0115-S4
Producer
OPP
Rigless
22-Nov-21
29-Nov-21
Caliper,Pressure -Temperature survey
OP26-DSP02
Disposalwell
OPP
Rigless
29-Nov-21
ongoing
MITIA, caliper, waterflow log
OP-12
Injector
OPP
Rigless
2-Dec-21
3-Dec-21
Memorygauge changeover
SP01-SE7
Producer
SID
Workover
Doyon 15
26-Dec-20
3-Jan-21
ESP Replacement
SP27-NlLl
Producer
SID
Sidetrack
Doyon 15
5-Jan-21
31-Jan-21
Pull ESP, Sidetrack, Install ESP
SP05-FN7
Producer
SID
Workover
Doyon 15
1-Feb-21
21-Feb-21
ESP Replacement
SP23-N3L1
Producer
SID
Sidetrack
Doyon 15
19-Feb-21
19-Mar-21
Pull ESP, Sidetrack, Install ESP
SP28-NW3
Producer
SID
Workover
Doyon 15
19-Mar-21
28-Mar-21
ESP Replacement
SI26-NW2
Injector
SID
Rigless
7-Apr-21
10-Apr-21
MITIA, Tubing leakdiagnostics
SP03-NE2
Producer
SID
Workover
Doyon 15
28-Mar-21
11-Apr-21
ESP Replacement
SP18-NSL1
Producer
SID
Sidetrack
Doyon 15
11-Apr-21
7-May-21
Pull ESP, Sidetrack, Install ESP
SP16-FN3L1
Producer
SID
Sidetrack
Doyon 15
7-May-21
31-May-21
Pull ESP, Sidetrack, Install ESP
S134-W6
Injector
SID
Rigless
15-May-21
5-Jun-21
MITIA, Tubingleak diagnostics
SI29-S2
Injector
SID
Rigless
10-Apr-21
5-Jun-21
MITIA, Tubing leak diagnostics
SI29-S2
Injector
SID
Workover
Doyon 15
5-Jun-21
16-Jun-21
Injection String Replacement
SP24-SE1
Producer
SID
Workover
Doyon 15
16-Jun-21
21-Jun-21
ESP Replacement
SP16-FN3
Producer
SID
Workover
Doyon 15
21-Jun-21
27-Jun-21
ESP Replacement
SP31-W7
Producer
SID
Workover
Doyon 15
27-Jun-21
12-Jul-21
ESP Replacement
SI26-NW2
Injector
SID
Workover
Doyon 15
12-Jul-21
25-Jul-21
Injection String Replacement
S102-SE6
Injector
SID
Drilling
Doyon 15
20-Aug-21
3-Dec-21
Grassroots injection well
SP09-E2
New Producer
SID
Drilling
Doyon 15
3-Sep-21
19-Dec-21
Grassroots producer well
SD37-DSP01
Disposal well
SID
Rigless
23-Oct-21
2-Nov-21
MITIA-tubing replacement
S102-SE6
Injector
SID
Drilling
Doyon 15
3-Dec-21
7-Dec-21
Re -drill grassroots injection well
SP30-WI
Producer
SID
Rigless
11-Dec-21
26-Dec-21
MITIA, Tubing leak diagnostics
SP09-E2 Ll
New Producer
SID
Drilling
Doyon 15
19-Dec-21
22-Jan-22
Dual Lat. Oil producer
Table 1: 2021 Nikaitchuq Field Drilling Rig Activity
The primary causes for well shut-ins and workovers are electrical submersible pump (ESP) failures
and tubing corrosion. To mitigate the corrosion risk, all workovers now incorporate coated
tubing. At the end of 2021, 6 active producing wells and 1 active injection well remained shut-in
pending rig interventions, which are planned in 2022. The planned well interventions are: 0115-
S4 (shut-in 10/25/21 due to MBE), SP05-FN7 (add 2nd lateral), OP14-S3 (shut-in 11/18/21 due
failed ESP), S115-El (grassroots injection well), OPO4-07 (shut-in 6/17/2021 due to failed ESP),
and OP10-09 (shut-in 12/17/21 due failed ESP). The remaining shut-in wells will be remediated
as the workover schedule develops in 2022.
On October 22, 2019, pursuant to A10 36.002 polymer injection was initiated in the Oliktok Point
1-2 (OP-12) well for a one-year test to determine the effectiveness of polymer injection for
improving recovery from the NSBOP. The test was cut short after 154 days due to logistical issues
resulting from the COVID-19 pandemic. The shortened test period resulted in inconclusive test
Eni Petroleum —Alaska Development Page 2
results. Eni resumed the polymer injection test in 2021 and has received Administrative Approval
under NO 36.003 to extend the test through December 31, 2022.
Routine maintenance was performed on the four power generation turbines and two gas
compressors at the Oliktok Production Pad (OPP), with one of the power generation turbines
receiving a complete overhaul replacement, and all receiving exhaust stack inspections and
associated repairs. In addition, cathodic protection inspections were completed on the sub -sea
production flowline from the offshore Spy Island Drill Site (SID) to OPP to ensure mechanical
integrity of the flowline bundle. In addition, the original radioactive sources in the four
Schlumberger PhaseWatcher test meters were replaced with new ones. These new sources will
be in service for 10 years.
In August/September 2021, a mandatory 10-year regulatory inspection of the many on -site tanks
and pressure vessels was completed in the Nikaitchuq field. This 23-day maintenance turnaround
was a significant effort and the entire Nikaitchuq field was down for the duration. PSD/ESD
testing occurred at the start of the shutdown. Mechanical integrity inspection results from the
2019 maintenance turnaround in the 11' POD helped guide additional inspection and repairs of
plant equipment and piping. Automation system and alarm management upgrades were also
complete during the turnaround
An Electrical Power Sharing (EPS) feasibility study was evaluated to interconnect the Oooguruk
and Nikaitchuq power generation systems to allow more robust and efficient power sharing
between the two fields. Funding for the EPS project has been approved and expected startup is
forecast for 2024.
Through additional drilling, well interventions, and consistent injection the NSBOP observed field
oil production and water cut are in line with Eni's reservoir model expectations. Annual average
daily NSBOP production during 2021 was 16,268 BOPD. Total oil production from the NSBOP
during 2021 was 5,937,952 barrels and is 68,522,579 barrels since field start-up thru 2021. The
annual average producing GOR and watercut were 148 SCF/STBO and 72%, respectively.
Annual average daily NSBOP injection during 2021 was 67,322 BWPD. Cumulative water injection
in the NSBOP during 2020 was 24,572,619 barrels and 149,848,699 barrels since the start of the
project. The 2021 annual and cumulative voidage replacement ratio were 1.09 and 1.00,
respectively. Attachment B details the 2021 voidage balance for the NSBOP. Pursuant to NO 36
Rule 8, Attachment F provides a summary of the mechanical integrity testing results and plans
for the NSBOP injection wells.
Eni Petroleum —Alaska Development Page 3
2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool
Thirty-nine pressure surveys recorded in 2021 were reported from 39 wells. This unusually large
number of surveys was the result of the field -wide shutdown of the plant (turnaround) from
approximately August 14th to September 8th,2021. This presented the opportunity to observe
the shut-in bottom hole pressure in every well with a working downhole gauge. In addition, there
were 2 grassroots wells with initial pressures reported. The pressure survey results are
summarized in the NSBOP Pressure Report, Form 10-412 (refer to Attachment Q. The NSBOP
Reservoir Pressure Map, Attachment D, depicts the estimated NSBOP average pressures for
December 2021 including shut-in and producing wells. The estimated average NSBOP reservoir
pressure is currently 1,680 psi at -3,760 ft. TVDss (datum). The 2021 average annual producing
GOR was 148 SCF/STBO and in December 2021 the GOR averaged 122 SCF/STBO (refer to
Attachment E, NSBOP Annual Reservoir Properties Report Form 10-428).
Reservoir management utilizes continuous pressure monitoring in both producers and injectors.
In addition to surface gauges measuring tubing pressures, Nikaitchuq oil producers are equipped
with downhole ESP gauges, providing both pump intake pressures (PIP) and discharge pressures,
which allow real-time bottom -hole pressure (BHP) monitoring. The data are used to optimize
production while also monitoring for signs of sand production, rising water cuts (WC), increasing
gas -oil ratios (GOR) and balancing voidage. During extended shut-ins the BHP data also provides
valuable surveillance and model input. Additionally, downhole gauges have been installed in
seven injection wells to assist in monitoring and calibration; five of these systems are currently
functional: OP-12 (temporary installation for polymer test, since September 2019), 0106-05, 0107-
04, S114-N6 and S125-1\12; two systems no longer transmit accurate data: 0111-01 and S120-N4.
Water injection targets maximizing voidage replacement and throughput in order to maximize
production and reserves. Consequently, injection pressures target the maximum pressure to not
exceed the fracture gradient, which can lead to early breakthrough events and poor flood
conformance; injection wellhead pressures, and if available BHPs, are continuously monitored
and injection rates adjusted accordingly. The operational target injection pressure limits are
significantly lower than the sandface limit of 2,400 psi prescribed by Alb 36, Rule 4 so that
injected fluids do not fracture the arresting or confining intervals or migrate out of the approved
injection strata.
Maps of the field pressures including shut-in and active wells, refer to Attachment D, are used
for monitoring performance, reservoir management and modeling. In December 2021 the datum
referenced average NSBOP producing well pressure was 691 psi (range: 416 psi to 1,559 psi), the
average injection well pressure was 1,973 psi (range: 1,085 psi to 2,135 psi), and areas outside
the influence of the development are at the initial pressure of 1,700 psi.
Eni Petroleum — Alaska Development Page 4
3.0 Results and Analysis of Production and Injection Log Surveys, Tracer
Surveys, Observation Well Surveys and Any Other Special Monitoring
Reservoir surveillance is routinely conducted to monitor well and reservoir performance and to
recommend changes in operating conditions, perform rate allocations, propose optimization
actions and address and solve general issues. Production allocations have been performed
continuously using well models that are calibrated with the most recent well tests. Reservoir
surveillance and monitoring activities in 2021 for the NSBOP included:
• Downhole and wellhead pressure and temperature real time measurements,
• ESP main performance parameter monitoring (e.g. current, voltage, motor temperature),
• Distributed Temperature Systems (DTS, fiber optics) monitoring lateral conformance
(fiber optics) in three wells: 0107-04, S114-N6 and S120-N4,
• Corrosion monitoring,
• Well performance indicative of tubing leaks or failing ESPs,
• Hydrocarbon and produced water surface sampling,
• Tracer sampling and interpretation in the OP-12 polymer pilot area,
• Well production tests,
• Continuation of the polymer flood testing pilot phase at the OP-12 well, and
• Planning and designing a test of the N-Sand in OP19 using a jet pump for lift.
Initially three OPP injectors (0106-05, 0107-04, 0111-01) and two SID injectors (S114-N6, S120-N4)
were equipped with DTS fiber optics, to quantify the conformance along the horizontal injection
intervals and monitor it over time. The DTS on the 0111-01 and 0106-05 were taken out of
commission. During 2020, due to investment restrictions planned DTS fall -off testing and
analyses were postponed to 2022.
Eni is currently performing an FOR pilot project focused on the use of polymer injection to
enhance overall recovery of the field. The pilot is planned in three phases:
• Phase 1: Short-term Injectivity test (completed in May 2019),
• Phase 2: One - year pilot injection test (initiated in late 2019, shutdown in March 2020
due to COVIDI9), and
• Phase 3: Full -Field Application (dependent on Phase 2 results and further review)
The first phase focused on assessing the feasibility of the activity by monitoring injection well
performance during polymer injection. For this stage, a 60 - day injectivity test was performed in
the OPP area with four wells each tested for two weeks with continuous polymer injection.
Testing was conducted from March 26, 2019 thru Friday, May 24, 2019. The wells tested were
0106-05, 0107-04, OP-12 and 0124. For each well a range of viscosities were tested, resulting in
no detrimental impact seen on any of the wells. All downhole pressures limits were honored. The
primary conclusion of the Phase 1 test is that the polymer selected for this study can be safely
Eni Petroleum —Alaska Development Page 5
and effectively injected into the Nikaitchuq reservoir. This conclusion cleared the way for a long-
term polymer injection pilot to evaluate the benefit of polymer injection on reservoir production.
For Phase 2, the OP-12 injection well, already tested in Phase 1, was selected as the long - term
pilot test candidate well. The planned duration of the test is 12 months with the option to extend.
Targets for polymer injection rates, and concentrations were determined from a simulation study
conducted by the Eni Milan FOR team. The pilot was initiated on October 22, 2019 with injection
of tracers early in the test phase with continuous sampling of offset production wells planned at
least through 2020. A downhole gauge was run in OP-12 and periodic falloffs are conducted to
assist in modeling the performance. Unfortunately, due to the COVID-19 pandemic operational
disruption the polymer injection pilot was shut down on March 23, 2020. Water injection
continued along with bi-monthly offset producing well sampling for tracer studies.
Phase 2 polymer injection was restarted in 2021 and continued throughout the year. Through
monitoring in adjacent production wells, OP-12 and OP-17, polymer has been detected, but only
in trace quantities. This is likely due to polymer left in the reservoir following the Phase 1
injectivity test and does not reflect a breakthrough of the Phase 2 polymer injection. These
production wells will continue to be monitored throughout the project. Then, depending on the
outcome of Phase 2, a full field polymer injection multidisciplinary feasibility study will be carried
out, in order to evaluate the full field application and the required surface modifications to the
existing facility network.
Eni Petroleum — Alaska Development Page 6
4.0 Review of Pool Production Allocation Factors and Issues Over the Year
Production from all wells producing from the NSBOP is commingled at the surface into a common
production line. Theoretical production for individual wells from the pool is calculated daily by
using well test allocations consistent with CO 639, Rule 8. Wells are tested at least twice per
month using Schlumberger Vx multiphase meters.
Daily theoretical production per well is calculated based on the last valid well testa nd the amount
of time that the well was on production for a given day:
MZn Ll teS produced
xDailyRate(BOPD) werrresr = TheoreticalDaily Production
1440Minut'"
day
The daily oil allocation factor for the field is calculated by dividing the actual total LACT meter
production for the day by the sum of the theoretical daily production for each individual well.
Subsequently, daily allocated production is assigned to each well by multiplying its theoretical
daily production by the daily allocation factor.
The average 2021 NSBOP oil allocation factor was 0.9514 as detailed in Table 2 below.
Month
Average Daily Allocation Factor
January
0.9982
February
0.9742
March
0.9566
April
0.9063
May
0.9677
June
0.9331
July
0.9493
August
0.9622
September
0.8892
October
0.9391
November
0.9703
December
0.9700
2021 Average
0.9514
Table 2: Average Field Allocation Factors for 2021
Eni Petroleum —Alaska Development Page 7
5.0 Reservoir Management Summary
The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under Conservation
Order No. 639 (CO 639) and Area Injection Order 36 (AIO 36) authorizing the injection of fluids
for pressure maintenance and enhanced oil recovery in the NSBOP. Consistent with the orders
the overall reservoir management objective is to maximize economic recovery and minimize
project risks while maintaining the highest environmental and safety standards.
The primary recovery mechanism for the field is waterflooding. Producers and injectors have
been drilled in pairs, located side by side and completed with horizontal drains in the OA sands.
Oil producer and water injector targets are defined based on historical producer -injector
waterflood responses, pressure trends, ESP constraints and well integrity limits. Water injection
targets maximizing voidage replacement and throughput in order to maximize production and
reserves. Injection pressures target the maximum pressure to not exceed the fracture gradient,
which can lead to early breakthrough events and poor flood conformance.
The hydrocarbon present in the Schrader Bluff is viscous and has low expansion energy and little
potential for gas expansion. Production and recovery are a result of waterflood displacement.
Artificial lifting is crucial for the well productivity; thus ESP failures represent one of most
significant risks to NSBOP production. Other significant risks are tubing, manifold and pipeline
leaks due to corrosion. Studies to understand and mitigate these risks are ongoing. This integrity
issue continues to negatively affect production, is costly to diagnose and is remediated through
tubing and ESP replacements.
Well constraints, for both injectors and producers, are based on historical analog field and well
performance, ESP capacity, pressure trends, waterflood pattern behavior, well integrity
conditions and ongoing operations. Individual well, pattern and field performance are routinely
reviewed and discussed with the Anchorage, Houston and Milan teams; pump intake targets and
injection well rate targets and pressure limits are defined and communicated to the lead field
operators along with guidelines to implement changes. The typical minimum pump intake
pressure targets 400 to 500 psi at the sandface, but is occasionally higher due to pump capacity
limits, gas locking at low pressures, sand production or other performance concerns. The
maximum injection pressure limit for all well's targets staying below the formation fracture
pressure and is continuously monitored by surface wellhead pressures; occasionally, lower
injection limits are implemented for diagnostic or operational purposes.
Eni Petroleum —Alaska Development Page 8
Reservoir management activities will continue in the NSBOP with the objective to:
• Maximize daily volumes and value by optimizing hydrocarbon production;
• Minimize risk exposure to key producing wells and maintain well integrity;
• Continue the Polymer Injection Pilot at OPP through 2022;
• Proactively define and develop mitigation plans related to water production;
• Proactively acquire reservoir performance data critical to reservoir management and
overall recoverable volumes determination;
• Ensure timely execution of reservoir surveillance plans, workovers, re -completions, and
infill drilling;
• Update current reservoir simulations and studies to reproduce the field behavior;
• Find cost-effective solutions to optimize the production.
Individual well and pattern surveillance data will continue to be collected to monitor
performance and improve recovery. A simulation model has been maintained and updated to
assist in reservoir development and flood management decisions in the NSBOP.
Eni Petroleum —Alaska Development Page 9
ATTACHMENT A
NSBOP Well Location Map
Nikaitchuq Development - As of December 2021
488000 492000 496000 500000 504000 508000 512000 516000 520000
iD SPO EZ 111v
t NE16 \
S -FN
p SI -FN \
' SP -FN \
e \ Ow[
0 51 iN1 \
SP2a1E2 PH \
I SP44{4
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SOf X
22-FNt v SN){N )
tp SP01 {!.
sOO SP28 44W3 S11}-E
SPO145ik \ \\ \ \
sit 1-N6 \\ \ \ \
g Mt \
O \ \
SP30•W I
SP23•N3 \ NN-04
\
iura4q S17 }.N2 E
g A SU2•W2
SP27411
SP33-w3
t
5114-wo - -- --- - 374)6P ,
covol-s1 py Ian
N SP31-W yun-1
4o e
OPI I-N
On5-S
o _ 0113-0 - --
OP10-09
7-5
23J ON7-04
17-02 1.52 OP03 PO
oP15.eiS4�4 oPiy �
-� ovu- o o11-01
0120-0i
- it :+89553
S
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So 011ktok Point
n
LEGEND
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Nikaltthoq Unit Boundary
c-
Du wod�«. win
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O
_ _ _ - Pnposed DeveloPntwells IP DL. WII
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m 1
488000 492000 496000 500000 504000 508000
Nikaitchtik Development
!Axle 57gna:u" 0 2000 4000 6000 B000f,U5
01105/2022 Alaska Dev. Team
' -'-'- 1:25000
i
o
m
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Eni Petroleum — Alaska Development Page 10
Produced Fluids
Produced
Oil, Gas,
Month MSTBO MMSCF
Cum Since Start -Up thru 2020»
Jan-21 499 57
Feb-21 483 61
Mar-21 554 73
Apr-21 481 69
May-21 535 98
Jun-21 525 99
Jul-21 577 104
Aug-21 277 52
Sep-21 378 56
Oct-21 578 80
Nov-21 530 68
Dec-21 519 63
Total 5,938 880
ATTACHMENT B
2021 NSBOP Voidage Balance by Month
Water,
MBBL
Year Cum
Total Cum since
Voidage, Voidage, start-up,
MRB MRB MRB
126,890
1,279
1,826
1,826
128,716
1,239
1,779
3,605
130,495
1,435
2,059
5,665
132,554
1,305
1,859
7,524
134,413
1,314
1,970
9,494
136,383
1,290
1,940
11,434
138,323
1,474
2,180
13,614
140,503
688
1,031
14,645
141,534
1,045
1,494
16,129
143,018
1,575
2,236
18,364
145,254
1,526
2,121
20,485
147,375
1,388
1,964
22,449
149,339
Fluids
Water Water Year
jection, Injection, Cum,
MSTB MRB MRB
im Since Start -Up thru 2020>:
2,095
2,095
2,095
2,105
2,105
4,200
2,265
2,265
6,464
1,795
1,795
8,259
1,986
1,986
10,245
1,948
1,948
12,193
2,275
2,275
14,469
1,180
1,180
15,649
1,666
1,666
17,315
2,408
2,408
19,723
2,422
2,422
22,144
2,428
2,428
24,573
Cum. since
start-up,
MRB
125,276
127,371
129,476
131,740
133,535
135,521
137,470
139,745
140,925
142,591
144,999
147,420
149,849
Net Injection
Net
Year
Cum since
Injection,
Cum,
start-up,
MRB
MRB
MRB
(1,613)
269
269
(1,345)
326
594
(1,019)
205
800
(814)
-64
735
(878)
16
751
(862)
8
760
(854)
96
855
(758)
149
1,004
(609)
182
1,186
(427)
172
1,358
(255)
301
1,659
46
464
2,123
510
2,173
Eni Petroleum -Alaska Development Page 11
ATTACHMENT C
NSBOP Pressure Report, Form 10-412
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator:
2. Address:
6ri US Operating Company Inc. Eni LIS)
3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503
3. Lh4 or Lease Narre:
4. Field and Pool:
5. Datum Reference:
6. 01 Gravity:
7. Gas Gravity:
NKAfrCHUCI
NKAITCHJO-SCFRADE3BLl1FFOL
3760
13-19
0.6
8. Wet Nacre
9. API Number
10. Type
11. AOGCC
12. Zone
13. Perforated
14. Final
15. Shut-h
16. Press.
17. Temp.
18. Depth
19. Final
20. Datum
21. Pressure
22. Pressure al
and Number:
50�
See
Pool Code
hlerval Top
Test Date
Ture, Fours
Surv. Type
d N
ToDSS
Observed
TVDSS (hput)
Gradient, pspft.
Datum (cal)
NO DASHES
hslructions
7VDSS
(see
Pressure at
instructions
Tool Depth
for codes
S02-Sit
506292367ODDDO
W
561100
Schrader Bluff
4,029
12t92021
Initial
SBFP
82
3,964
1,045
3,760
0."
947
SF09F2
50629237DOODDO
O
561100
Schrader Bluff
4.090
111WO22
hitial
SBFP
87
4,082
1,824
3.760
0.41
1,691
OP03-05
1 50029233960000
O
1 5611 D0
Schrader Bluff
1 3.631
8/142021
600
SSHP
1 77
3.454
1 1,215
3,760
1 0.41
1.341
OPO4-07
50029234090000
O
561100
Schrader Bluff
31780
8/142021
3,480
SBFP
83
3.626
1,250
3,760
0.41
1,305
OP05-06
5DO29234270000
0
561100
Schrader Bluff
3.751
8/142021
4.008
SBFP
92
3.717
1.201
3.760
0.41
1,219
OPoB-04
50029234240D00
O
5611DO
Schrader Bluff
34567
8/142021
60)
SBFP
73
3.482
826
3,760
0.41
941
OF09-Sl
50029234480000
O
561100
Schrader Buff
3.851
6/142021
912
SBFP
76
3,498
754
3.760
0.41
662
OP10-09 I
50029234390000
O
561100
Schrader Bluff
3,637
8/142021
600
S13 P
75
3.531
926
3,760
0.41
1,021
OP12-01
5002923426ODDO
O
561100
Schrader Bluff
3,554
8/142021
600
SBFP
70
3,053
816
3,760
0.41
1,108
OP14-S3
5DO29234470000
O
561100
Schrader Stuff
3.776
8/142021
600
SBFP
75
3.624
762
3,760
0.41
860
OP1&03
50029234420000
O
561100
Schrader Bluff
3,378
8/142021
600
SBFP
68
3,202
1,047
3.760
0.41
1,278
OP17-02
5D029234310000
O
5611DO
Schrader Bluff 1
3.460
6/14/2021
600
58FP
73
3,460
am
3.760
0.41
1,008
OPI8-08
50029234490D00
O
561100
Schrader Bluff
3.432
8/14/2021
600
SBFP
76
3.384
511
31760
0.41
667
SP01-SE7
SM29235420000
O
561100
Schrader Bluff
41108
8/142021
600
SBFP
91
4,047
877
3,760
0.41
758
SP03-NU
50629236390000
O
561100
Schrader Bluff
4.040
8/142021
600
SBFP
88
4,025
1688
3.760
0.41
1.578
23. Ali tests reported hereh ware made in accordance w Rh the applicable rules, regulations and instructions of the Alaska 01 and Gas Conservation Comhsslcn.
I hereby certify that the foregoing is hue and correct to the best of cry knowledge. Dlgira0y signed by:8ehh Alan Lope.. --
OrpaK�6j..asppp:�Nl US OP_c01Nc/67-0JI5446
Date30/03720221259:30
Signature -- Tale Production Engineer
Printed Nacre Keith Lopez Date April 1, 2022
Eni Petroleum -Alaska Development Page 12
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator.
Eni us OperatingCompany kic. Ent US
2. Address:
3700 CenterPoint DrNe, Suite 500, Anchorage, AK 99503
3. Unit or Lease Nave:
NKArrCMX]
4. Field and Pool:
NKAIrCFUO.SCH7ADERBLUFFOL
S. Datum Reference:
3760
6. Ol Gravity:
13-19
7. Gas Gravely:
0A
8. Wet Nana
and Nunber.
9. AR hLnber
50�
NO DASHES
10, Type
Sae
instructions
11. AOGCC
Pool Code
12. Zone
13. Perforated
interval Top
T7DSS
14. Final
Test Dale
15. Shut-in
T41e, Hours
16. Press.
Surv. Type
(see
nst-tons
for codes
17. Tenp.
18, Depth
Tool NDSS
19. Final
Observed
Pressure at
Tool Depth
20. Datum
NDSS (npul)
21. Pressure
Gradient, psHfl.
22. Pressure at
Datum (cal)
SPU4SE5
5062923537ODDO
O
561100
Schrader Bluff
41052
8/14/2021
1 600
SBHP
84
3.904
1.085
3,760
0.41
1,026
SP05-FN7
50629234810000
O
561100
Schrader Bluff
3,942
8/142021
600
SBHP
82
3,790
1.269
3.760
0.41
1,277
SW8-N7
5062923501ODDO
O
561100
Schrader Bluff
4,038
8/142021
6W
SBHP
as
3.900
1 1,185
3,760
0.41
1,127
SP1041,15
5062923473DOW
O
5611DO
Schrader Bluff
3,845
8/142021
600
SBHP
82
3.679
1.049
3.760
0.41
1,083
SP12-SE3
$0629235130000
O
561100
Schrader Bluff
3.961
8/142021
600
SBHP
84
3,765
1,440
3,760
0.41
1.438
SPI6-FM
50629234670000
0
561100
Schrader Bluff
3,763
a1142021
600
SBHP
79
3.636
1,051
3,760
0.41
1.102
SPIB-N5
606292345300DO
O
561100
Schrader Bluff
3.939
8/142021
600
SBHP
86
3,929
1,250
3.760
0.41
1.180
SP21-NW1
50629235200000
0
561100
1 Schrader Bluff
3,580
8/142021
1 600
SBIP
1 75
3.292
565
3.760
0.41
759
SP22-FN1
5W29234780000
O
5611DO
Schrader Bluf(
31666
8/142021
6D0
SBHP I
T7
3,429
856
3.760
0.41
993
BP23-M
50629234560000
O
561100
Schrader Bluff
3.030
8/142021
600
SBHP
82
3,816
890
3,760
0.41
867
SP24-SE1
50629235100000
O
561100
Schrader Bluff
3,891
8/142021
6W
SBHP
80
3,745
604
3.760 1
0.41
810
SP27-Ni
50629234550000
O
561100
Schrader Bluff
3,677
8/142021
600
SBHP
79
3,623
009
3.760
0.41
866
SP28-NM
50629235560000
0
561100
Schrader Bluff
3.561
8/142021
60D
SBHP
79
3.282
728
3,760
0.41
926
SP30-WI
50629234760000
O
561100
Schrader Bluf(
3,625
8/142021
600
SBIHP
82
3,499
649
3.760
0.41
.7
SP31-W7
5WZ9235320D00
0
561100
Schrader Bluff
3.420
6/142021
600
SBHP
71
3,202
492
3.760
0.41
723
23. AN tests reported herein were node in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Comrisson.
I hereby certify that the foregoing is hue and correct to the best of my Inow ledge. Digit Ily signed byKeilh Alan Lopez
OrgaPlzal1ea:ENl UBAP. C01N I8T.715446
Date:30/01 72022'13:00:¢S'" '-•
Signature -. Title Production Engineer
Printed Marne Keith Lopez Date April 1, 2022
Eni Petroleum -Alaska Development Page 13
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
RESERVOIR PRESSURE REPORT
1. Operator
Ent US Operating Company Inc. Eni US
2.Address:
3700 Center oinl Drive, Suile 500, Anchorage. AK 99503
3. Unit or Lease Name:
NKARCHUQ
4. Field and Pools
NKAfrCHUD-SCHRADER BLUFF OL
5. Datum Reference:
3760
6. 01 Gravity:
13-19
7. Gas Gravity:
0.6
B. Well Name
and Number:
9. AR Number
SOX%XXXXXXXXXX
NO CASHES
10. Type
See
Instructions
l 1. AOGCC
Pool Code
12. Zone
13. Perforated
Interval Top
TVDSS
14. Final
Test Dale
15. Shuldn
Time, Hours
16. Press.
Surv. Type
(see
instructions
for codes
17. Temp.
18. Depth
Tod TVDSS
19. F al
Observed
Pressure at
Tool Depth
20. Datum
TVDSS (input)
21. Pressure
Gradient, payft.
2.2. Pressure at
Datum (ca0
SP33-VJ3
50629234800000
0
561100
Schrader Bluff
3,525
8/142021
600
SBHP
75
3.078
917
3,760
0.41
1,199
SP36-W5
5062923492ODDO
O
561100
Schrader Bluff
3.463
8/142021
600
SBHP
68
3.150
970
3,760
0.41
1,222
OM05
5W29234370000
Vvl
561100
Schrader Bluff
3,635
8/142021
600
SBHP
81
3.654
1,5m
3.760
1 0.44
1,561
0107-D4
50029234350000
WI
561100
Schrader Bluff
3,618
8/142021
600
SBHP
95
3,593
1,306
3,760
0.44
1,379
0111-01
SM292343D000D
Wl
561100
Schrader Bluff
3.574
8/142021
600
SBHP
97
3,538
1,425
3.760
0.44
1,523
SIO&N=1
50629236580000
Vv1
561100
Schrader Bluff
3,986
8/14/2021
600
SBHP
81
3.925
1.744
3,760
0.44
1,671
SI14-M
W62923507ODDO
Vd
5611D0
Schrader Bluff
4.000
8/142021
600
SBHP
93
3,959
1,257
3.760
0.44
1.169
Sr2&N/
50629234660000
w
561100
Schrader Boff
3.889
8/142021
600
SBHP
97
3.857
1.462
3,760
0.44
1,419
S25-W
50629234720000
wl
5611DO
Schrader Bluff
3,670
8/142021
600
SBHP
94
3,687
1,127
1 3,760
0.44
1.159
23. AN tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska 01 and Gas Conservation Cormisslon.
I hereby certify that the foregoing is true and correct to the best of my knowledge. Digitally signed by:Keiln Alem Lopez
Orga�(aaaon:6Nl US DP_.INc/9]-D71544fi
Date11 3/20221306:34 .�- -
Signature -- Tme Production Engineer
Printed Nana Keith Lopez Data April 1, 2022
Eni Petroleum -Alaska Development Page 14
ATTACHMENT D
NSBOP Reservoir Pressure December 2021
48a0UJ
I'l , ...:CiiO 5_C00] _-:O.:C '0:°._;CI 5._.00 _ OC,..
_200_,.
o
1
I II
�i
rn
Federal
o
O
D
I
-4:77- ss
m
0
7
O
O
o
o
i9wc
m
a
g
SP
0
II
a
T
�t
rv.
a
a
a
o
�
:a
_
m
`G
o
o
c�
m
o
g
pN
-
o
N
O
K
OO
O
P
Y
1
tpD
7
O
O
b
O
pOp
O
ID
O
O
O
2m�
xm
2t4hOliklok
Pant
xm
\
2M:
/
W
um
csc
�
0
01
x
N
t0
e:o
!
m
O
u
4Et1000
492000 406000 500000 504000 seem 512000 51600J
5=rk
524{00
Nikaitchu_k_
Development
Aue- —
—Syrue;.e 0 2000 4000 6000 8000ttUS
0320,2022
Alaska Dev Team ra ME SOMEONE
125000
eni
Eni Petroleum —Alaska Development Page 15
ATTACHMENT E
NSBOP Annual Reservoir Properties Report, Form 10-428
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
ANNUAL RESERVOIR PROPERTIES REPORT
1. OPxata:
2. AdNms:
6J Potrale�m
3]00 Gaoler QNe. Su4e 500. Arrlcr ,Alaala 9950]
3. Fe ad Pod
4, Pod Krm
5. Refaerce
fi.
]. Porpay
6_ fkmnabNy
9. S I (%)
10, Q
11. a
12. OriprW
1J. Bupbk
14. MeM
15. Oi
1fi. Gae
t). Gms
16_!!I
19. Q'giW
20_ DrAde Poi4
21. Crs
22. dipiid
2]. drreni
FyEe:
C§lumlft
Tenpereaae
(%)
lad
Vacmy�
Vecpay�
Resave
Poiaa
Rnervpi
0revpy
sp�'
Fay(f1)
Fvy(ft)
Famepsn
FaneOpn
(bnprnaaity
GOR
GOR
NOSSI
(-F)
c'9"
Sahaepon
(pag
Dew Rwrl
Ressae
(-AM
G y(At
Vppme
Vduee Facia
Fach.(2)
(scFrslfi)
(6CF5T9)
Reasae
R.—(cp)
Ressae
psi)R&s
W)
-1.6)
Facia
B
(P M)
.11.
Scfveeer Wf
37W
70-90
15.35
50. 1000
13-45
90-2(p
]0-1.
1](p
600.1200
1660
13-19
06
30-e0
25-40
1.045
1.05
03-0.6
60-140
1u
Digitally signed bYKnN Alan Lopez
Ihaepy cer0fY 11W tree faeppigc true aid caretib Oro pest pl
anvw OrD�v2Alipn.ENIUsoP. CO'INC/9]-0]1546
PY 1e30° Oate 30M37202213:01, it'"�'.... � -
$9—.
Rotluctlon fipiieer
iak
P1.w ]Cme KeN Lp�
mb 1- �
En! Petroleum —Alaska Development Page 16
ATTACHMENT F
NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8)
Well
PTD#
Status
Date s
Last Test
Result
Frequency
(Years)
Due Date
Injecting
since MIT
due date?
O P-12
206-144
WINJ
3/21/2021
P
4
3/20/2025
Yes
016-05
210-165
WINJ
6/27/2021
P
2(AA)
6/27/2023
Yes
017-04
210-153
WINJ
3/21/2021
P
4
3/20/2025
Yes
0111-01
210-106
WINJ
3/21/2021
P
4
3/20/2025
Yes
0113-03
211-100
WINJ
5/6/2021
P
4
5/5/2025
Yes
0115-S4
211-141
WINJ
6/3/2021
P
2(AA)
6/3/2023
Yes
0120-07
211-140
WINJ
6/4/2021
P
4
6/3/2025
Yes
0124-08
211-130
WINJ
3/23/2021
P
4
3/22/2025
Yes
5102-SE6
220-019
WINJ
12/15/2021
P
4
12/14/2025
Yes
S106-N E1
219-165
WINJ
5/1/2021
P
4
4/30/2025
Yes
S107-SE4
214-100
WINJ
2/26/2022
P
4
2/25/2026
Yes
S111-FN 6
213-128
WINJ
5/1/2021
P
4
4/30/2025
Yes
S113-FN 4
212-156
WINJ
4/30/2021
P
4
4/29/2025
Yes
S114-N 6
213-194
WINJ
4/30/2021
P
4
4/29/2025
Yes
5117-SE2
214-041
WINJ
4/30/2021
P
4
4/29/2025
Yes
S119-FN2
213-043
WINJ
4/30/2021
P
4
4/29/2025
Yes
S120-N 4
212-029
WINJ
4/30/2021
P
4
4/29/2025
Yes
S125-N2
212-090
WINJ
4/30/2021
P
4
4/29/2025
Yes
S126-N W2
214-157
WINJ
8/14/2021
P
4
8/13/2025
Yes
S129-S2
212-006
WINJ
6/26/2021
P
4
6/25/2025
Yes
5132-W2
213-013
WINJ
4/30/2021
P
4
4/29/2025
Yes
S134-W6
215-016
WINJ
5/16/2021
P
2 (AA)
5/16/2023
Yes
5135-W4
213-101
WIND 1
4/30/2021
P
4 1
4/29/20251
Yes
Eni Petroleum —Alaska Development Page 17
