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HomeMy WebLinkAbout225-075Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/21/2026
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20260121
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF
T41253
BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf
T41254
BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf
T41255
BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf
T41256
BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf
T41257
BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf
T41258
BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf
T41259
BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun
T41259
GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf
T41260
IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf
T41261
IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf
T41261
IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug
T41261
IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf
T41261
KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf
T41262
KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF
T41263
KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun
T41264
LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf
T41265
MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL
T41266
MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL
T41267
MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL
T41268
MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut
T41268
MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL
T41269
NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug
T41270
NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT
T41271
NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT
T41272
NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug
T41272
NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf
T41272
NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF
T41273
OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch
T41274
NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.01.21 13:56:35 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275
SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276
SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277
SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278
TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279
TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280
TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280
TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281
Please include current contact information if different from above.
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.01.21 13:56:51 -09'00'
From:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Date:Friday, December 19, 2025 2:23:48 PM
From: Rixse, Melvin G (OGC)
Sent: Friday, December 19, 2025 2:22 PM
To: 'Eric Dickerman' <eric.dickerman@hilcorp.com>
Subject: RE: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Eric,
Hilcorp is approved to proceed as described below.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Friday, December 19, 2025 10:57 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Mel,
Following up on our phone call.
Prior to setting a plug and abandoning the perforations underneath, we are requesting approval to
perform a production log after the clean out, re-perforate target intervals based on the log results,
then add the Beluga H perforations previously requested. After the re-perf and add perf, we will
flow the well and evaluate if a plug is still necessary to optimize production. I have attached the
revised program and it is summarized below.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Plan:
1. Coiled tubing - fill cleanout.
2. Eline - production log.
3. Eline - re-perforate target intervals based on production log results.
4. Eline - add perforations in the Beluga H (same intervals from 10-403).
5. Flow test, evaluate production.
6. Evaluate if a plug is necessary. If a plug is necessary to prevent water/fill entering the
wellbore, ensure one is set at 7100’ with a 25’ cement cap.
Regards,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Friday, December 19, 2025 8:57 AM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC)
<dave.roby@alaska.gov>
Subject: RE: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Eric,
For this sundry, AOGCC will accept a single bridge plug with 25’ of cement set at 7100’
MD. I will add this requirement to the wireline work of this sundry.
Please note that in the future, AOGCC may be requiring more frequent permanent
isolation for long TVD sections. This approval should not be interpreted as a blanket
approval for significant TVD distances to crossflow perpetually. Past experiences, such
as the challenges Hilcorp faced in milling out plugs for final abandonment, highlight the
importance of considering more frequent isolation.
Let me know if there are any questions or additional details needed.
Mel Rixse
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains
information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of
Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such
information may violate state or federal law. If you are an unintended recipient of this e-
mail, please delete it, without first saving or forwarding it, and so that the AOGCC is
aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or
(Melvin.Rixse@alaska.gov).
cc. Roby, Dewhurst
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Wednesday, December 17, 2025 1:27 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC)
<dave.roby@alaska.gov>
Subject: Re: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Mel,
Would a bridge plug set at +/- 7,100' md/6,023' tvd with 25' of cement dump bailed on
top of the bridge plug be acceptable?
Regards,
Eric Dickerman
Hilcorp CIO OE
307-250-4013
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Wednesday, December 17, 2025 12:06 PM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC)
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
<dave.roby@alaska.gov>
Subject: [EXTERNAL] PTD 225-075 NCIU A-21A Sundry Request 325-748 Plug and PerfEri
Eric,
In the final abandonment of this well, AOGCC will require cement isolation between
6354’ TVD and 5481’ TVD. 875’ TVD of crossflow without a permanent barrier does not
provide isolation to assure formation fluids are confined to their respective indigenous
strata.
AOGCC would consider cement isolation or an intermediate plug with dump bailed
cement as acceptable isolation. Alternatively, a commitment to drill out the CIBP at
6500’ MD or place a drillable plug for the final abandonment would be considered
acceptable.
Let me know how you would like to address so we can approve this sundry request.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Andy Dewhurst, Dave Roby
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,734 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
12/15/2025
4-1/2"
LTP & Baker Onyx-R5E TRSSSV (MD) (TVD) & (MD) (TVD)
Perforation Depth MD (ft):
5,395 - 7,465
6,237'
4,469 - 6,354
6,601'4-1/2" 7,724'
30"
9-5/8"
384'
1,610'
MD
1,630psi
6,870psi
384'
1,562'
384'
1,610'
Length Size
Proposed Pools:
L-80
TVD Burst
1,520
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
225-075
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21A
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Other:
North Cook Inlet Tertiary System Gas Same
6,610 7,639 6,522 1,524psi N/A
CO 68A
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.12.08 14:34:41 -
09'00'
Dan Marlowe
(1267)
325-746
By Grace Christianson at 3:01 pm, Dec 08, 2025
A.Dewhurst 19DEC25 DSR-12/8/25
* Service coil BOPE pressure test to 3500 psi. 48-hour notice to AOGCC for opportunity to witness.
* Additional lower abandonment CIBP to be set at ~7100' MD and 25' of cement to be dump bailed
for permanent barrier to possible future cross flow.
10-404
MGR19DEC2025JLC 12/19/2025
12/19/25
Fill Clean Out, Plug, and Perf
Well: North Cook Inlet Unit A-21A
Well Name:NCIU A-21A API Number:50-883-20199-01-00
Current Status:Online, Gas Well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-075
First Call Engineer:Eric Dickerman (907) 564-4061
Second Call Engineer:Casey Morse (907) 777-8322
Maximum Expected BHP:2,158 psi at 6,349 TVD - 0.34 psi/ft Shut in BHP survey 8/24/2025
Max. Potential Surface Pressure: 1,524 psi MPSP -0.1 psi/ft gas grad. to surface
Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool
Brief Well Summary:
NCIU A-21A was drilled and completed in August 2025 in the Beluga Formation. Initial production rates were
3.9 mmscfd, however in mid October production rates started to decline and finally on 10/21/2025, the well
went to zero flow.Recently NCIU A-06A, has successfully produced from intervals that were bypassed in NCIU
A-21A because they were thought to be wet.
Objective:
Coiled tubing fill cleanout to return well to production.Shut off intervals contributing fill with bridge plug at
6,500. Add perforations.
Wellbore information:
A passing 3,000 psi 9-5/8 x 4-1/2 liner lap test was performed on 8/16/25.
A passing MIT-T and CMIT-TxIA was performed to 3,000 psi on 8/17/25.
An FIT was performed to 14.8 ppg at 1,562 tvd (0.77 psi/ft).
North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, at 3,657 md / 3,247 tvd.
North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands (below TD).
Fill Clean Out, Plug, and Perf
Well: North Cook Inlet Unit A-21A
Coiled Tubing Cleanout:
1. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
2. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48hr witness notification for BOP test.
3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to PBTD at 7,596.
a. Working fluid will be 6% KCl (8.6 ppg).
b. Take returns to surface from the coiled tubing by 4-1/2 annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
4. Hand well over to production to test and attempt to determine which interval is contributing fill.
Repeat fill cleanout as necessary.
5. RDMO CTU.
Eline:
6. MIRU Eline.
7. Pressure test PCE to 250 psi low / 3,500 psi high.
8. Set 4-1/2 CIBP at ± 6,500.
9. Perforate the following intervals.
Sand
Interval
Perforation
Top
(MD)
Perforation
Bottom
(MD)
Perforation
Interval
Footage
(ft.)
Beluga_Ha 6321 6332 11
Beluga_Hb 6345 6350 5
Beluga_Hc 6392 6411 19
10. RDMO Eline, hand well over to production for flow test.
CONTINGENCY Eline plug/patch: (if able to diagnose which interval(s) is causing fill/water problems)
11. RU Eline and Nitrogen assist.
12. Pressure test PCE and treating iron to 250 psi low / 3,500 psi high.
13. Pressure up tubing to target pressure with N2 as needed.
14. Set 4-1/2 CIBP or patch to shut off unwanted perforated interval per Operations Engineer.
15. RDMO Eline and Nitrogen.
Attachments:
1. Correlation log
2. Proposed Wellbore Schematic
3. CT BOP Drawing
4. Nitrogen procedure
* Additional lower abandonment CIBP to be set at ~7100' MD and 25' of cement to be dump bailed
for permanent barrier to possible future cross flow. - mgr
0
Fill Clean Out, Plug, and Perf
Well: North Cook Inlet Unit A-21A
Correlation Log:
_____________________________________________________________________________________
Updated By: JLL 12/08/25
PROPOSED North Cook Inlet Unit
NCIU A-21A
PTD: 225-075
API: 50-883-20199-01-00
4
5/6/7
8
1
23
A-21
PBTD = 7,639 / TVD = 6,522
TD = 7,734 / TVD = 6,610
RKB = 126.6
Bel A
Bel B
Bel G
Bel F
Bel E
BelD
Bel C
Bel S
Bel Q
Bel P
Bel O
Bel N
Bel M
Bel L
Bel K
Bel J
Bel I
Bel H
4-1/2
8-1/2
hole
12-1/4
hole
30
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30Conductor Driven
to Set Depth - - Weld 29 Surf 384
9-5/8" Surf Csg 47 L-80 DWC/C 8.681 Surf 1,610 TOW
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958 1,487 7,724
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT 3.958 Surf 1,520
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 404 404 3.813 Baker Onyx-R5E TRSSSV w/ 3.813" profile
2 1,008 1,006 - ES Cementer
3 1,399 1,380 3.833 GLM, 4.5" X 1.5'' FO-2
4 1,457 1,433 3.813 X-Nipple Giant Oil Tool
5 1,511 1,480 3.900 Seal Assembly
6 1,487 1,459 3.900 Liner hanger / LTP Assembly
7 1,610 1,562 8.681 9-5/8 Whipstock
8 ±6,500 ±5,481 - CIBP
Notes
5,639 RA Tag
6,638 RA Tag
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD)
Btm
(TVD)FT Date Status
Bel Aa 5,395' 5,414' 4,469' 4,486' 19' 8/28/2025 Open
Bel Ab 5,441' 5,454' 4,510' 4,522' 13' 8/28/2025 Open
Bel Ba 5,561' 5,568' 4,621' 4,628' 6' 8/28/2025 Open
Bel Bb 5,573' 5,578' 4,633' 4,637' 5' 8/28/2025 Open
Bel Bc 5,595' 5,599' 4,653' 4,657' 4' 8/28/2025 Open
Bel Ca 5,644' 5,647' 4,699' 4,701' 3' 8/28/2025 Open
Bel Cb 5,656' 5,661' 4,710' 4,714' 5' 8/28/2025 Open
Bel Cc 5,666' 5,672' 4,719' 4,724' 6' 8/28/2025 Open
Bel Cd 5,679' 5,694' 4,731' 4,745' 15' 8/28/2025 Open
Bel Da 5,812' 5,815' 4,853' 4,855' 3' 8/27/2025 Open
Bel Db 5,840' 5,843' 4,878' 4,881' 3' 8/27/2025 Open
Bel Dc 5,854' 5,868' 4,891' 4,904' 14' 8/27/2025 Open
Bel Ea 5,888' 5,913' 4,922' 4,945' 25' 8/27/2025 Open
Bel Eb 5,974' 5,981' 5,001' 5,008' 7' 8/27/2025 Open
Bel Ec 6,027' 6,046' 5,050' 5,067' 19' 8/27/2025 Open
Bel Fa 6,074' 6,080' 5,093' 5,098' 6' 8/27/2025 Open
Bel Fb 6,101' 6,105' 5,118' 5,121' 4' 8/27/2025 Open
Bel Fc 6,128' 6,131' 5,143' 5,145' 3' 8/27/2025 Open
Bel Ga 6,150' 6,156' 5,163' 5,168' 6' 8/27/2025 Open
Bel Gb 6,174' 6,194' 5,185' 5,203' 20' 8/27/2025 Open
Bel Gc 6,204' 6,213' 5,212' 5,220' 9' 8/27/2025 Open
Bel Gd 6,216' 6,223'5,223' 5,229' 7'8/27/2025 Open
Bel Ge 6,242' 6,247' 5,247' 5,251' 5' 8/27/2025 Open
Bel Ha ±6,321 ±6,332 ±5,515 ±5,524 ±11Future Proposed
Bel Hb ±6,345 ±6,350 ±5,535 ±5,539 ±5 Future Proposed
Bel Hc ±6,392 ±6,411 ±5,574 ±5,590 ±19Future Proposed
Bel I 6,514' 6,518' 5,494' 5,498' 4' 8/24/2025 Isolated
Bel Ja 6,557' 6,561' 5,533' 5,537' 4' 8/24/2025 Isolated
Bel Jb 6,631' 6,636'5,600' 5,604' 5'8/24/2025 Isolated
Bel Ka 6,724' 6,733' 5,684' 5,692' 9' 8/24/2025 Isolated
Bel Kb 6,739' 6,744'5,698' 5,702' 5'8/24/2025 Isolated
Bel L 6,771' 6,777' 5,726' 5,732' 6' 8/24/2025 Isolated
Bel M 6,905' 6,917'5,848' 5,858' 12'8/24/2025 Isolated
Bel Na 6,943' 6,948' 5,882' 5,887' 5' 8/23/2025 Isolated
Bel Nb 6,957' 6,971'5,895' 5,907' 14'8/23/2025 Isolated
Bel O 7,007' 7,020' 5,940' 5,952' 13' 8/23/2025 Isolated
Bel Pa 7,114' 7,118'6,037' 6,040' 4'8/23/2025 Isolated
Bel Pb 7,123' 7,126' 6,045' 6,047' 3' 8/23/2025 Isolated
Bel Qa 7,162' 7,193' 6,080' 6,108' 31' 8/23/2025 Isolated
Bel Qb 7,286' 7,316'6,201' 6,219' 20'8/23/2025 Isolated
Bel Sa 7,460' 7,465' 6,349' 6,354' 5' 8/22/2025 Isolated
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 387 bbls Stg 2 - 428 bbls
4-1/2 TOC @ TOL (40% excess) L 420 bbls / T 40 bbls
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,734 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
11/6/2025
4-1/2"
LTP & Baker Onyx-R5E TRSSSV (MD) (TVD) & (MD) (TVD)
Perforation Depth MD (ft):
5,395 - 7,465
6,237'
4,469 - 6,354
6,601'4-1/2" 7,724'
30"
9-5/8"
384'
1,610'
MD
1,630psi
6,870psi
384'
1,562'
384'
1,610'
Length Size
Proposed Pools:
L-80
TVD Burst
1,520
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
225-075
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21A
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Other: CT FCO, N2
North Cook Inlet Tertiary System Gas Same
6,610 7,639 6,522 1,524psi N/A
CO 68A
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.10.22 16:39:54 -
08'00'
Dan Marlowe
(1267)
325-661
By Grace Christianson at 9:45 am, Oct 23, 2025
DSR-10/30/25A.Dewhurst 23OCT25
* BOPE test to 3500 psi. 48 hour notice.
10-404
MGR31OCT25JLC 10/31/2025
11/03/25
Fill Clean Out
Well: North Cook Inlet Unit A-21A
Well Name:NCIU A-21A API Number:50-883-20199-01-00
Current Status:Shut in, Gas Well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-075
First Call Engineer:Eric Dickerman (907) 564-4061
Second Call Engineer:Casey Morse (907) 777-8322
Maximum Expected BHP:2,158 psi at 6,349 TVD - 0.34 psi/ft Shut in BHP survey 8/24/2025
Max. Potential Surface Pressure: 1,524 psi MPSP -0.1 psi/ft gas grad. to surface
Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool
Brief Well Summary:
NCIU A-21A was drilled and completed in August 2025 in the Beluga Formation. Initial production rates were
3.9 mmscfd, however in mid October production rates started to decline and finally on 10/21/2025, the well
went to zero flow.
Objective:
Coiled tubing fill cleanout to return well to production. Attempt to determine zone contributing fill, then shut
off with either a perf straddle or a bridge plug.
Wellbore information:
A passing 3,000 psi 9-5/8 x 4-1/2 liner lap test was performed on 8/16/25.
A passing MIT-T and CMIT-TxIA was performed to 3,000 psi on 8/17/25.
An FIT was performed to 14.8 ppg at 1,562 tvd (0.77 psi/ft).
North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, at 3,657 md / 3,247 tvd.
North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands (below TD).
Fill Clean Out
Well: North Cook Inlet Unit A-21A
Slickline:
1. MIRU Slickline.
2. Pressure test PCE to 250 psi low / 2,500 psi high.
3. Drift to PBTD.
4. RDMO Slickline.
Coiled Tubing Cleanout:
5. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
6. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48hr witness notification for BOP test.
7. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to PBTD at 7,596.
a. Working fluid will be 6% KCl (8.6 ppg).
b. Take returns to surface from the coiled tubing by 4-1/2 annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
8. Hand well over to production to test and attempt to determine which interval is contributing fill.
Repeat fill cleanout as necessary.
9. RDMO CTU.
CONTINGENCY Eline plug/patch: (if able to diagnose which interval(s) is causing fill problems)
10. RU Eline and Nitrogen assist.
11. Pressure test PCE and treating iron to 250 psi low / 3,500 psi high.
12. Pressure up tubing to target pressure with N2 as needed.
13. Set 4-1/2 CIBP or patch to shut off unwanted perforated interval per Operations Engineer.
14. RDMO Eline and Nitrogen.
Attachments:
1. Proposed Wellbore Schematic
2. CT BOP Drawing
3. Nitrogen procedure
_____________________________________________________________________________________
Updated By: JLL 09/23/25
SCHEMATIC North Cook Inlet Unit
NCIU A-21A
PTD: 225-075
API: 50-883-20199-01-00
4
5/6/7
1
23
A-21
PBTD = 7,639 / TVD = 6,522
TD = 7,734 / TVD = 6,610
RKB = 126.6
Bel A
Bel B
Bel G
Bel F
Bel E
BelD
Bel C
Bel S
Bel Q
Bel P
Bel O
Bel N
Bel M
Bel L
Bel K
Bel J
Bel I
4-1/2
8-1/2
hole
12-1/4
hole
30
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30Conductor Driven
to Set Depth - - Weld 29 Surf 384
9-5/8" Surf Csg 47 L-80 DWC/C 8.681 Surf 1,610 TOW
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958 1,487 7,724
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT 3.958 Surf 1,520
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 404 404 3.813 Baker Onyx-R5E TRSSSV w/ 3.813" profile
2 1,008 1,006 - ES Cementer
3 1,399 1,380 3.833 GLM, 4.5" X 1.5'' FO-2
4 1,457 1,433 3.813 X-Nipple Giant Oil Tool
5 1,511 1,480 3.900 Seal Assembly
6 1,487 1,459 3.900 Liner hanger / LTP Assembly
7 1,610 1,562 8.681 9-5/8 Whipstock
Notes
5,639 RA Tag
6,638 RA Tag
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD)
Btm
(TVD)FT Date Status
Bel Aa 5,395' 5,414' 4,469' 4,486' 19' 8/28/2025 Open
Bel Ab 5,441' 5,454' 4,510' 4,522' 13' 8/28/2025 Open
Bel Ba 5,561' 5,568' 4,621' 4,628' 6' 8/28/2025 Open
Bel Bb 5,573' 5,578' 4,633' 4,637' 5' 8/28/2025 Open
Bel Bc 5,595' 5,599' 4,653' 4,657' 4' 8/28/2025 Open
Bel Ca 5,644' 5,647' 4,699' 4,701' 3' 8/28/2025 Open
Bel Cb 5,656' 5,661' 4,710' 4,714' 5' 8/28/2025 Open
Bel Cc 5,666' 5,672' 4,719' 4,724' 6' 8/28/2025 Open
Bel Cd 5,679' 5,694' 4,731' 4,745' 15' 8/28/2025 Open
Bel Da 5,812' 5,815' 4,853' 4,855' 3' 8/27/2025 Open
Bel Db 5,840' 5,843' 4,878' 4,881' 3' 8/27/2025 Open
Bel Dc 5,854' 5,868' 4,891' 4,904' 14' 8/27/2025 Open
Bel Ea 5,888' 5,913' 4,922' 4,945' 25' 8/27/2025 Open
Bel Eb 5,974' 5,981' 5,001' 5,008' 7' 8/27/2025 Open
Bel Ec 6,027' 6,046' 5,050' 5,067' 19' 8/27/2025 Open
Bel Fa 6,074' 6,080' 5,093' 5,098' 6' 8/27/2025 Open
Bel Fb 6,101' 6,105' 5,118' 5,121' 4' 8/27/2025 Open
Bel Fc 6,128' 6,131' 5,143' 5,145' 3' 8/27/2025 Open
Bel Ga 6,150' 6,156' 5,163' 5,168' 6' 8/27/2025 Open
Bel Gb 6,174' 6,194' 5,185' 5,203' 20' 8/27/2025 Open
Bel Gc 6,204' 6,213' 5,212' 5,220' 9' 8/27/2025 Open
Bel Gd 6,216' 6,223' 5,223' 5,229' 7' 8/27/2025 Open
Bel Ge 6,242' 6,247'5,247' 5,251' 5'8/27/2025 Open
Bel I 6,514' 6,518' 5,494' 5,498' 4' 8/24/2025 Open
Bel Ja 6,557' 6,561' 5,533' 5,537' 4' 8/24/2025 Open
Bel Jb 6,631' 6,636' 5,600' 5,604' 5' 8/24/2025 Open
Bel Ka 6,724' 6,733' 5,684' 5,692' 9' 8/24/2025 Open
Bel Kb 6,739' 6,744'5,698' 5,702' 5'8/24/2025 Open
Bel L 6,771' 6,777' 5,726' 5,732' 6' 8/24/2025 Open
Bel M 6,905' 6,917'5,848' 5,858' 12'8/24/2025 Open
Bel Na 6,943' 6,948' 5,882' 5,887' 5' 8/23/2025 Open
Bel Nb 6,957' 6,971'5,895' 5,907' 14'8/23/2025 Open
Bel O 7,007' 7,020' 5,940' 5,952' 13' 8/23/2025 Open
Bel Pa 7,114' 7,118'6,037' 6,040' 4'8/23/2025 Open
Bel Pb 7,123' 7,126' 6,045' 6,047' 3' 8/23/2025 Open
Bel Qa 7,162' 7,193'6,080' 6,108' 31'8/23/2025 Open
Bel Qb 7,286' 7,316' 6,201' 6,219' 20' 8/23/2025 Open
Bel Sa 7,460' 7,465' 6,349' 6,354' 5' 8/22/2025 Open
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 387 bbls Stg 2 - 428 bbls
4-1/2 TOC @ TOL (40% excess) L 420 bbls / T 40 bbls
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/02/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20251002
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF
T40937
BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF
T40938
BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF
T49038
BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG
T40938
BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF
T40939
BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF
T40940
BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf
T40941
BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch
T40942
BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf
T40942
END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF
T40943
END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF
T40944
END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF
T40945
KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf
T40946
KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF
T40947
KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF
T40948
KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf
T40948
MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL
T40949
MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL
T40950
MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf
T40951
MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf
T40952
NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL
T40953
NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF
T40954
PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL
T40955
PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL
T40956
SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf
T40957
SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf
T40958
SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf
T40958
Please include current contact information if different from above.
NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.10.03 09:00:56 -08'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): North Cook Inlet
GL: N/A BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 101 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
4-1/2" L-80 6,600'
4-1/2" L-80 1,487'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press.24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl:Water-Bbl:
0 2416561
9/14/2025 24
Flow Tubing
24
3932
N/A39320
Choke Size:
1,459'
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#7,724'
Water-Bbl:
PRODUCTION TEST
8/25/2025
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
1,487'
Tieback Assy.
8-1/2"
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
12.6#Surface 1,520'Surface Tieback
N/A
1,610' MD / 1,562' TVD
404' MD / 404' TVD
7,734' MD / 6,610' TVD
7,639' MD / 6,522' TVD
205' FSL, 613' FEL, Sec 36, T12N, R10W, SM, AK
607' FSL, 1440' FEL, Sec 36, T12N, R10W, SM, AK
AMOUNT
PULLED
330428
329606
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
GRADE CEMENTING RECORD
2588207
SETTING DEPTH TVD
2588622
TOP HOLE SIZEBOTTOMCASINGWT. PER
FT.
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
332001 2586725
50-883-20199-01-00August 3, 2025
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
8/22/2025 225-075 / 325-448 / 325-449
N/A
NCIU A-21AAugust 12, 20251254' FNL, 982' FWL, Sec 6, T11N, R9W, SM, AK
126.6'
Tertiary System Gas Pool
ADL 17589 / ADL 37831
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
TUBING RECORD
L - 1123 sx / T - 180 sx
CBL 8-22-25, Perf / GPT Logs, LWD ( BST, STS, CTN, ALD, PWD, DDSR)
PACKER SET (MD/TVD)
G
s d 1
0 p
d B P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
Received by J. Brooks on
9/23/2025 at 3:00pm
Complete
8/22/2025
JSB
RBDMS JSB 102325
GDSR-11/26/25MGR29DEC2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel A 5395' 4469'
5372' 4448'
5642' 4697'
5887' 4921'
6051' 5072'
6266' 5269'
6541' 5518'
6751' 5708'
6943' 5883'
7052' 5983'
7142' 6065'
7321' 6230'
7441' 6341'
7661' 6497'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Bel T
Bel P
Bel F
Bel A
Bel H
Bel N
Bel C
Bel E
Bel J
Bel L
Bel Q
Bel R
Bel S
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Report, Definitive Directional Survey
Authorized Title: Drilling Manager
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.09.23 14:55:33 -
08'00'
Sean
McLaughlin
(4311)
_____________________________________________________________________________________
Updated By: JLL 09/23/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-21A
PTD: 225-075
API: 50-883-20199-01-00
4
5/6/7
1
23
A-21
PBTD = 7,639’ / TVD = 6,522’
TD = 7,734’ / TVD = 6,610’
RKB = 126.6’
Bel A
Bel B
Bel G
Bel F
Bel E
Bel D
Bel C
Bel S
Bel Q
Bel P
Bel O
Bel N
Bel M
Bel L
Bel K
Bel J
Bel I
4-1/2”
8-1/2”
hole
12-1/4”
hole
30”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 1,610’ TOW
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 1,487’ 7,724’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT 3.958” Surf 1,520’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 404’ 404’ 3.813 Baker Onyx-R5E TRSSSV w/ 3.813" profile
2 1,008’ 1,006’ - ES Cementer
3 1,399’ 1,380’ 3.833 GLM, 4.5" X 1.5'' FO-2
4 1,457’ 1,433’ 3.813 X-Nipple Giant Oil Tool
5 1,511’ 1,480’ 3.900 Seal Assembly
6 1,487’ 1,459’ 3.900 Liner hanger / LTP Assembly
7 1,610’ 1,562’ 8.681 9-5/8” Whipstock
Notes
5,639’ RA Tag
6,638’ RA Tag
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD)
Btm
(TVD)FT Date Status
Bel Aa 5,395' 5,414' 4,469' 4,486' 19' 8/28/2025 Open
Bel Ab 5,441' 5,454' 4,510' 4,522' 13' 8/28/2025 Open
Bel Ba 5,561' 5,568' 4,621' 4,628' 6' 8/28/2025 Open
Bel Bb 5,573' 5,578' 4,633' 4,637' 5' 8/28/2025 Open
Bel Bc 5,595' 5,599' 4,653' 4,657' 4' 8/28/2025 Open
Bel Ca 5,644' 5,647' 4,699' 4,701' 3' 8/28/2025 Open
Bel Cb 5,656' 5,661' 4,710' 4,714' 5' 8/28/2025 Open
Bel Cc 5,666' 5,672' 4,719' 4,724' 6' 8/28/2025 Open
Bel Cd 5,679' 5,694' 4,731' 4,745' 15' 8/28/2025 Open
Bel Da 5,812' 5,815' 4,853' 4,855' 3' 8/27/2025 Open
Bel Db 5,840' 5,843' 4,878' 4,881' 3' 8/27/2025 Open
Bel Dc 5,854' 5,868' 4,891' 4,904' 14' 8/27/2025 Open
Bel Ea 5,888' 5,913' 4,922' 4,945' 25' 8/27/2025 Open
Bel Eb 5,974' 5,981' 5,001' 5,008' 7' 8/27/2025 Open
Bel Ec 6,027' 6,046' 5,050' 5,067' 19' 8/27/2025 Open
Bel Fa 6,074' 6,080' 5,093' 5,098' 6' 8/27/2025 Open
Bel Fb 6,101' 6,105' 5,118' 5,121' 4' 8/27/2025 Open
Bel Fc 6,128' 6,131' 5,143' 5,145' 3' 8/27/2025 Open
Bel Ga 6,150' 6,156' 5,163' 5,168' 6' 8/27/2025 Open
Bel Gb 6,174' 6,194' 5,185' 5,203' 20' 8/27/2025 Open
Bel Gc 6,204' 6,213' 5,212' 5,220' 9' 8/27/2025 Open
Bel Gd 6,216' 6,223' 5,223' 5,229' 7' 8/27/2025 Open
Bel Ge 6,242' 6,247'5,247' 5,251' 5'8/27/2025 Open
Bel I 6,514' 6,518' 5,494' 5,498' 4' 8/24/2025 Open
Bel Ja 6,557' 6,561' 5,533' 5,537' 4' 8/24/2025 Open
Bel Jb 6,631' 6,636' 5,600' 5,604' 5' 8/24/2025 Open
Bel Ka 6,724' 6,733' 5,684' 5,692' 9' 8/24/2025 Open
Bel Kb 6,739' 6,744'5,698' 5,702' 5'8/24/2025 Open
Bel L 6,771' 6,777' 5,726' 5,732' 6' 8/24/2025 Open
Bel M 6,905' 6,917'5,848' 5,858' 12'8/24/2025 Open
Bel Na 6,943' 6,948' 5,882' 5,887' 5' 8/23/2025 Open
Bel Nb 6,957' 6,971'5,895' 5,907' 14'8/23/2025 Open
Bel O 7,007' 7,020' 5,940' 5,952' 13' 8/23/2025 Open
Bel Pa 7,114' 7,118'6,037' 6,040' 4'8/23/2025 Open
Bel Pb 7,123' 7,126' 6,045' 6,047' 3' 8/23/2025 Open
Bel Qa 7,162' 7,193'6,080' 6,108' 31'8/23/2025 Open
Bel Qb 7,286' 7,316' 6,201' 6,219' 20' 8/23/2025 Open
Bel Sa 7,460' 7,465' 6,349' 6,354' 5' 8/22/2025 Open
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 387 bbls Stg 2 - 428 bbls
4-1/2” TOC @ TOL (40% excess) L – 420 bbls / T – 40 bbls
TOC ~at TOL per CBL
21-AUG-2025
Page 1/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:7/23/2025 End Date:
Report Number
1
Report Start Date
7/23/2025
Report End Date
7/24/2025
Operation
Secure lines to tugboats. Lower hull to 13' draft, legs free and floating away from Bruce Platform. Continue jacking Legs up until all manhole covers in Spud cans are out
of water. Rig under way to Tyonek platform. Checking watertight integrity every 30 mins and keeping tow log. Currently .5 miles out from Tyonek Platform.
Report Number
2
Report Start Date
7/24/2025
Report End Date
7/25/2025
Operation
Position rig towards Tyonek platform. 07:00 rig is on location.
Legs pinned @ 07:05, PSO begin post clearance monitoring for 30 mins. Raise hull 6’ air gap, dump water from bow tanks.
Raise hull to 0’ air gap at high tide. Disconnect all tugs from rig @ 08:20, tugs stand by 500 yards from rig. Jack hull up and release tugs @ 11:30. Prepare for preloading.
Remove blanking flanges on all preload tanks. Perform sonar scan of sea floor.
Hold PJSM with all involved personnel. Complete preload stages 1-4 of rig move preload schedule. Hold preload for 2 hours while monitoring stability of rig. Clean rig
while waiting.
Dump and strip preload tanks in preparation for jacking up rig. Install 3 wing deck. Continue to clean and organize.
Report Number
3
Report Start Date
7/25/2025
Report End Date
7/26/2025
Operation
Continue stripping water from preload tanks. Finish installing port wing deck. Pick and secure hoses under rig floor to clear Tyonek sub-base.
Start jacking motors & warm up hydraulics. Jack rig up to clear Tyonek sub-base.
Remove stow clamps from cantilever beams. Turn on skid pumps and stroke cylinders in preparation to skid cantilever out.
Skid cantilever over sub-base on Tyonek.
Install gangway f/rig – t/platform and secure same. Change out hydraulic valve bank on skid HPU. Install H.P. lines to skid jacks and remove all clamps sub-base. Skid
sub-base 3' to back of platform. Transverse sub-base to the port side 3'. Measure and check orientation of sub-base to rig. Remove gangway.
Skid cantilever back in.
Jack rig down 5” to top of sub-base measurement and skid cantilever out 8’. Install gangway f/rig – t/platform and secure same.
Spot 13 5/8" Annular, Double Gate, Single gate, Mud Cross, Choke and Kill HCR's in sub-base. Remove gangway.
Skid cantilever out over sub-base. Align sub-base with bottom of drilling package, Install bolts.
Install shim plates on hydraulic jacks on sub-base. Begin unbolting drilling package from cantilever.
Report Number
4
Report Start Date
7/26/2025
Report End Date
7/27/2025
Operation
Finish removing bolts that connect cantilever and drilling package.
Disconnect service lines from cantilever to drilling package, remove V-door.
Remove storm clamps on transverse beams. Transverse drilling package to STBD side to align with sub-base. Install storm clamps back on transverse beams.
P/U drilling package with sub-base jacks. Jack hull of rig down to clear cantilever beams. Skid cantilever in to clear drilling package.
Lower jacks on sub-base and remove all shim plates from sub-base.
Tighten bolts f/sub-base – t/rig. Install C-Plates to sub-base and tighten.
Remove bell nipple and flow box from rotary. Install R/U lines to TDS.
Install 2 HAK beams onto cantilever and secure.
Place and secure 13 5/8” annular no top section of sub-base. Stack and N/U single gate, flow cross, double gate and HCR valves inside sub-base.
Transverse drilling package to square up. Skid drilling package over to A-21. Safe out w/ handrails on open deck.
Remove handrails and install gangway f/rig – t/platform and secure. Install slide f/rig – t/platform for service lines and hoses.
Install 3rd HAK beams onto cantilever and secure.
Begin installation of HAK deck frames to beams on cantilever and secure.
Report Number
5
Report Start Date
7/27/2025
Report End Date
7/28/2025
Operation
Weld HAK frames to beams. Install HAK deck on frames/beams and install handrails.
Skid and transverse sub-base over well. Install all storm clamps.
Loosen storm clamps on transverse beams on drilling package, transverse rig floor well center. Install storm clamps and tighten.
Remove overboard dump plates from inside all mud pits. Safe out HAK deck w/handrails. Troubleshoot TDS dolly retract and extend proximity switches. Install H.P. mud
line f/rig – t/drilling package and secure. Install V-Door and walkway. Install and calibrate rig gas detection system.
Install 2" H.P. cement line f/cement unit – t/drilling package and secure. Fit and weld flowline flange and flow line. Spot MWD shack on port wing deck on upper cantilever.
Torque bolts on 13 5/8 BOP's and choke and kill HCR'/Manual valves. R/U to stab 5' Riser spool onto double gate of BOP's.
Stab and N/U 5’ spacer spool onto BOP’s. Install BOP lifting flange and hang BOP from BOP trolly. Lower and position choke, kill and Koomey lines into sub-base.
Continue to R/U service lines and hoses. Dress shakers with screens. Change Koomey fittings on single gate. Offload boat with drill pipe and mud chemicals. Begin
building mud. Begin rig acceptance check list.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151Permit to Drill (PTD) #:225-075
Wellbore API/UWI:508832019901000
Page 2/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Report Number
6
Report Start Date
7/28/2025
Report End Date
7/29/2025
Operation
Finish lowering and positioning choke, kill and Koomey lines into sub-base.
Make and hook up service hoses/lines from rig to platform and drilling package.
Install handrails from walkway to HAK deck. Install walkway from Aft of rig to Platform. Remove plates on flowline ditch to shale shakers. Install saltwater service line to
drilling package. M/U flowline to flange.
Nipple up 1502 flange to top of tree. Install 2" H.P. hose with "T" and Lo-Torque valves.
Pump through flow box and flowline all the way to shakers and check for leaks. Pump through all pop off valves w/ mud pumps to confirm flow path. Test H.P. mud hose
and pump in assembly to 3000 psi, good test,
Open well, observed 130 psi on TBG. Begin bullheading well at 1 BPM 80 psi. Pressure increased to 140 psi and broke to 80 psi. Continue bullheading at 1.5-2.0 BPM,
after 62 bbls pumped pressure increased to 2500 psi. Pumped 1 more bbl and pressure increased to 3000 psi. Shut pumps off and monitor well. No increase or decrease
in pressure. Bleed pressure off and observed 240 psi. R/U to bleed back to Trip tank, bleed back .7 bbls. Shut well in observed 0 psi. Open 2" Bleed off valve on rig floor,
well gasing. Shut well in and R/U to bleed off through production. Shut well in to monitor, 0 psi. R/D pump in assembly.
Assist Vault Rep w/ install of BPV in Tbg Hanger.
N/D production tree and surface safety valve. Removed from well head room.
N/U 11” x 13 5/8” DSA to riser. Install hose to overboard line.
Report Number
7
Report Start Date
7/29/2025
Report End Date
7/30/2025
Operation
Cont. N/U 11” x 13 5/8” DSA to riser. Install hose to overboard line.
N/U DSA/riser t/wellhead. Installing BOP on riser, flange on 5ft riser hitting sub base I-beam not allowing BOP t/sit straight up/dwn.
Remove BOP f/riser and reconfigure BOP's, set annular on sub base and start pulling dbl gate and mud-X. L/D mud-X, M/U dbl gate t/single gate, set annular and 5ft riser
on dbl , M/U all connections. Work boat-off load diesel f/ISO's and back load same on boat.
Cont. m/u all connections, stab LP riser into flow box and annular air boot adaptor,m/u same, inflate air boots. Install xo's, Choke/kill HCR's and manual valves. M/U 5"
test jt assy.
AOGCC Rep Adam Earl arrived @09:30hrs. t/witness BOP test.
Install 5" test jt into well and flood same w/FIW, purge air f/system, attempt t/pshell test-bled off fast, screw in test jt furthur as per Vault rep., re-test leaking,fix leak on kill
line hose connection. Good shell test t/3000psi f/5min. @04:00hrs.
Test BOPE w/5" and 4-1/2" jts t/250psi-low and t/3000psi-high f/5min. charted as per AOGCC/Hilcorp AK polic. 4 of 11 test completed at report time.
Report Number
8
Report Start Date
7/30/2025
Report End Date
7/31/2025
Operation
Test BOPE w/5" jts t/250psi-low and t/3000psi-high f/5min. charted as per AOGCC/Hilcorp AK polic. 7 of 12 test completed, test witnessed by AOGCC inspector/Adam
Earl. Perform accumulator draw down. R/D 5" test jt and r/u 4-1/2" testjt.. Cont. test w/4-1/2"jt 11 of 12 test completed. Function BOP's f/remote station as per policy.
Pull 4-1/2" test jt and remove blanking plug, re-install and evacuate water from stack, L/D test jt. Pull BPV w/Vault Rep., install TWC.
Perform test on blind rams t/250psi-low and 3000psi-high f/5min. each. 12 of 12 test completed.
Pull TWC w/Vault Rep., L/D T bar.
M/U vault tbg hanger Running tool t/landing jt. install into hanger, r/u HP hose t/side entry pump in sub. Attempt to bull head fluid into perf.s @ 1bpm, pressure increased
t/4000psi w/2.9bbls pumped, bled back 2.2bbls. Monitor well no pressure of fluid increases.
Install overboard line, install API/20 mesh shaker screens on scalpers and API/120 mesh on rig shakers. Rebuild MP #3 bleeder valve and test same t/1000psi-good.
Re-torq all BOP connections. Secure HP hoses and install chaffing buffers around hoses on sub base/beaver slide.
Install fill and bleeder hoses t/anulus f/trip tank with bleeder t/choke line t/poorboy. Fill annulus w/291bbls FIW. R/D same, L/D landing jt and prep to p/u 5"DP.
P/U 5"dp and rack in derrick.
Report Number
9
Report Start Date
7/31/2025
Report End Date
8/1/2025
Operation
P/U 1std of 5"dp and screw in top drive and check derrick/top drive alignment.
P/U 6std of 5"HWDP, drift and rack in derrick.
P/U 64stds of 5" 19.9# DP, drift and rack in the derrick, applying break in trq to new pipe as needed.
P/U and M/U landing jt w/running tool as per Vault Rep., 5ft in landing jt and land on depth, engage hanger as per Vault rep., issue w/procedure, dis-engage hanger
andpull running tool to surface. Running tool hadsnap ring retainer, removed retainer and collet f/running tool. Re-check breaks on way back in, loose connection @ IBT
thread, M/U same, land on depth, engage hanger as per Vault rep., install TIW, Kelly up and pump 350psi on tbg.. Close annular. Attempt to pull thru annular, pull 110k,
work hoist wt t/170k. s/o t/ block wt. and open annular, pulled hanger free w/95k up wt.. Close annular. Hold pre-job on displacing well w/clean FIW w/crew and production
Operator.
Displace well w/9# KCL @1.5bpm, 92psi, taking returns t/production maifold. 395bbls pumps t/production.
Report Number
10
Report Start Date
8/1/2025
Report End Date
8/2/2025
Operation
Monitor well-static, R/D pumping assy and c/o elevator. Pull Hanger t/rig floor, L/D same.
Pre-job, r/ul/d 4.5" tbg w/Parker Wellbore. L/D tbg f/5701' tsurf.', monitoring fill on the TT. 18SS band collected and all control lne f/SSSV. R/D 4.5" handling equipment.
Service rig-grease Top drive/blocks, crown, draw works, ST-80. Flush thru flow box w/water and soap, skim trip tank.
R/U 5" handling equipment and M/U running tool and set wear rig, L/D running tool and rack std.
R/U 2-7/8" handling equipment and Parker wellbore. strap tbg in the V-door. P/U mule shoe-jt and rabbit same.
Pump out Trip Tanks, finish strapping tbg. P/U 15jts and XO, c/o handling equipments t/5".
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 3/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
RIH w/2-7/8" cement stinger on 5"DP f/511' t/6235', R/U cement hose and circ. head.
Report Number
11
Report Start Date
8/2/2025
Report End Date
8/3/2025
Operation
CIrc btm up .
Circ. B/U @6235',336 gpm, 1300 psi.
Line up to cmt unti. Pump 10 bbl FIW & test lines to 3000 psi. Good. Mix & Pump 40 BBL balance plug at 15.3 PPG and fox chase with 10 bbl. Displace with rig pumps
at 6 BPM 78 BBL. R/D Circ lines and POOH slow with dry pipe.
POOH F/ 6234' T/ 5294' slow with dry pipe. Drop Foam ball & circ at 10 BPM . Saw Trace cmt at btm up and dump returns over board. Displace well to clean FIW.
POOH F/ 5294' T/ 511'. R/U & L/D 2 7/8 tubing. Saw cmt on out side of 2 7/8. Clean pipe as needed. Clear floor of tubing equipment.
P/U 8-1/2" bit and bit sub w/float. RIH f/4' t/4911', kelly up and fill pipe, wash dwn f/5000' t/5300' @1bpm, 100psi. Tag TOC @5300' w/20k dwn.
P/U 10ft and test casing @3000psi f/10min.-good, bleed off.
State Rep. Cam StJohn/AOGCC on site to witness tag and test. S/O and tag cement @1bpm, 100psi and 15k set dwn TOC@5300'. P/U 10ft and shut Top pipe rams, test
casing t/3274psi f/30min. on a chart -good. Staring pressure 3274psi, 15min. 3203psi, 30min. 3170psi. 5.6bbls pumped, 5.5bbls bled back.
R/D test equipment.
POOH f/5280' t/surface, L/D bit/bit sub. monitor fill on the TT.
Circ. 55bbl ConDen pill thru stack/choke manifold and trip tanks t/sand trap and chase w/10bbls FIW.
Single in the hole w/50 jts 5"DP, POOH and rack same.
Report Number
12
Report Start Date
8/3/2025
Report End Date
8/4/2025
Operation
Finish single in the hole w/50 jts 5"DP, POOH and rack same.
Clean trip tank #2 and sand traps1 thru 4. R/U 2"hp hose f/rig floor t/well bay.
P/U 1 std f/derrick and L/D btm single, M/U TM collar, DM collar, float sub and bit. Test MWD tool w/400gpm, 600psi. Breakoff bit and float sub, M/U 15ft pup on btm and
rack same in derrick.
Pre-job on P/U whi stock/mill BHA. LP/U mill assy and 1jt. HWDP t/49'.
P/U and M/U Haliburton directional assy and WIS 9-5/8" whipstock assy f/49' t/101'.
Trip in the hole w/whipstock assy on 5"dp f/101' t/1634', slowly, filling every std.
Kelly up and bring onpumps t/420gpm, 1005psi. Cycle pumps and correlate TF, set whip stock as per WIS/Sperry t/139deg LOHS, Top of window @1610'md, btm of
window @1624'md.
Displace well t/9.0ppg LSND and purging all lines/pumps, overboard all FIW f/well. Fill all sand traps f/lower pits.
Mill window f/1610' t/1644', 400gpm, 1400psi, 50-90rpm, 3-4k trq. P/U=88k, S/O=88k. Retrieved 406# metal shavings f/ditch magnets @0600hrs. Ream window 1.5 w/o
issue. Having difficulty drifting window -s/o stacking 10-20k set dwn w/5rpm.
Report Number
13
Report Start Date
8/4/2025
Report End Date
8/5/2025
Operation
Not able to drift window passed 1614', Backream window 1x w/o issue. Having difficulty drifting window -s/o stacking 10-20k set dwn w/5rpm, descision made t/pull mill
and inspect same.
Perform FIT test @1610'md/1562'tvd t/470psi(14.8 target ppg). w/9.0ppg test MW, pumped 2.73bbls w/1/6bbls bled back. Sent FIT/LOT test sheet t/engineer.
POOH f/1610' t/77', monitoring fill on the TT.
L/D Milling BHA#1 as per WIS/Sperryf/77' t/surface, btm and middle mills 3/16" under gauge, top mill 1/16" under gauge.
C/O red tugger cable, c/o screens on scalpers. Install Twister HMI/screen f/top drive in drillers shack. w/NOV Rep..
M/U washing tool on std, wash well head and BOP's @410gpm, 90psi and 10rpm. Clean all madnets. Install NOV updates on TDS11. Trouble shoot extend function
proximity switch.
P/U and M/U 8-1/2"bit and 6-3/4" directional assy. t/54'.
TIH f/54' t/1448', Kelly up, bring on pumps and orient tool face, make connection and bring on pumps t/400gpm, 876psi, s/o and tag @ TOW1610'. Make several attempts
w/o entering window.
POOH f/1610' t/surface. monitoring fill on the TT.
Drain mud motor, break off bit (broken jet) L/D motor and directional assy..
M/U WIS string mill BHA#2- w/window mill and string mill.
TIW w/string mill assy. f/100' t/1591', Kelly up wash dwn @400gpm, 300psi, 55rpm, 2k trq off btm. S/O and tag @1610' w/2k set dwn.
Dress window f/1610' t/1644', w/400gpm, 300psi, 55rpm, 1-2k trq, 0-2k wob. 436# total metal recovered f/magnets @0600hrs. Majority of time spent on upper part of slide
1610'-1614', where it kept hanging up.
Report Number
14
Report Start Date
8/5/2025
Report End Date
8/6/2025
Operation
pump 30bblhi-vis sweep and circ. B/U @400gpm, 296psi, 20rpm, 1-2k trq.
POOH f/1600' t/surface, break out float sub, string and window mill and l/d same. Monitored fill on the TT.
P/U BHA#3 as per Haliburton DD/MWD. M/U bit, mtr and mwd tools. Scribe same, shallow test, p/u and load sources.
RIH f/54' t/1500', while monitoring displacement on the TT.
Fill pipe @1500', kelly up, bring on pump and align tool face t/139deg. shut dwn pump. S/O and slide thru TOW@1610' t/1644' w/o issue.
Drll/slide 8-1/2" hole as per DD/wp04 f/1644' t/1820', 400gpm, 940psi,12-18k wob, 2-3k trq..
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 4/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Take on bottom survey, circ. B/U clean @400gpm, 875psi, 50rpm.
POOH f/1820' t/1646', take survey align TF t/window, cont. POOH f/1646' t/51', monitoring fill on the TT.
L/D BHA#3 directional assy as per DD/MWD.
P/U BHA#4 as per DD/MWD, M/U 8-1/2' PDC bit /motor, M/U MWD tools and upload data, latch std HWDP and break off float sub and m/u on top BHA, RIH and shallow
test same @450gpm/800psi-good. Pull up and hold pre-job on loading sources, load sources.
RIH t/950', monitoring displacement o the TT.
While RIH, heard load pop and observed loss of draw works power, crew investigated and found plug house ext. smoke/arc flash from DC cable plug end, c/o cable and
end w/o further issue.
Service TDS, draw works, crown and ST-80. Assist NOV Tech. w/software update f/TDS, Twister HMI and trouble shoot extend on TDS, work as directed RIH t/1521'.
Kelly up @1521' w/400gpm, 730psi and orient tool face, shut dwn pump and slide thru window w/o pumping t/1820'. No fill on btm.
Drill/slide f/1820' t/ 2178, 450gpm, 990psi, rpm, 2-3k trq, 1-2k wob, 9.6ECD p/u=100k, s/o=90k, rt=95k.
SPR's @1840'md w/9.0ppg
pump#1: 20stks/100psi, 30/150, 40/200
pump#2: 20stks/100psi, 30/150, 40/200
Report Number
15
Report Start Date
8/6/2025
Report End Date
8/7/2025
Operation
Drill/slide f/2178' t/ 2557', 450gpm, 1090psi, rpm, 2-3k trq, 1-2k wob, 9.6 ECD p/u=120k, s/o=100k, rt=108k, max gas 107 units, madd pass all slide >20', dbl back ream
connection, hi-vis sweep every 500' or as needed. Pump 30bbl sweep @2220' w/10% increase in cuttings-returned on time.
Drill/slide f/2557' t/ 2841', 450gpm, 1100psi, rpm, 50rpm, 5-6k trq, 1-2k wob, 9.6 ECD p/u=130k, s/o=110k, rt=112k, max gas 107 units, madd pass all slide >20', dbl back
ream connection, hi-vis sweep every 500' or as needed. Pump 30bbl sweep @2220' w/10% increase in cuttings-returned on time.
Obtain SPR's
Circ. hole clean, rot/recip. f/2841' t/2781', 450gpm, 1000psi, 40rpm, 5k trq.
POOH f/2841' t/1820', monitoring fill on the TT.
MWD computer locked up, MWD trouble shoot with IT. Waiting to Madd Pass.
MadPass f/1820' t/1755', 450gpm, 1000psi, 40rpm,2k trq @200fph. MadPass f/1755' t/1638', 450gpm, 950psi, @200fph. POOH f/1638' t/1519' w/no pump or rotation and
TF lined up to the window @1624' t/1610'.
Service rig: grease block, top drive, draw works, ST-80, crown, work w/NOV tesch. and rig electrician on top drive extend function-targets need to be modified. Function
test all BOP components except the blind rams f/drillers HMI and cantilever HMI remote station.
RIH f/1519' t/2749', monitoring displacement on the TT. Fill pipe and wash dwn t/2841', 425gpm, 1000psi, 10rpm, 5k trq, no fill.
Drill/slide f/2841' t/ 3219', 450gpm, 1200psi, rpm, 50rpm, 5-6k trq, 1-2k wob, 9.9 ECD p/u=130k, s/o=110k, rt=112k, max gas 107 units, madd pass all slide >20', dbl back
ream connection, hi-vis sweep every 500' or as needed.
Report Number
16
Report Start Date
8/7/2025
Report End Date
8/8/2025
Operation
Drill/slide f/3219' t/ 3614', 450gpm, 1150psi, 50rpm, 7-8k trq, 1-2k wob, 9.8 ECD p/u=150k, s/o=105k, rt=120k, madd pass all slide >20', dbl back ream connection, hi-vis
sweep every 500' or as needed.
Drill/slide f/3614' t/3885', 450gpm, 1187psi, 50rpm, 8-9k trq, 1-3k wob, 18 max gas, 9.4MW, 9.9 ECD p/u=155k, s/o=105k, rt=122k, dbl back ream connection, madd pass
all slide >20', hi-vis sweep every 500' or as needed.
Circ. B/U x3 @450gpm, 1136psi, 50rpm, 8-10k trq, Spot 40bbl/50ppb LCM pill f/1610' dwn(window).
Flow check-static, POOH f/3885' t/2749', monitoring fill on the TT.
Service rig: grease draw works, top drive/block, static loss rate=.6bph.
RIH f/2749' t/3885', monitored displacement on the TT. wash dwn last std, 300gpm, 615psi, 20rpm, no fill.
Drill/slide f/3885' t/4167', 460gpm, 1260psi, 50rpm, 8-10k trq, 1-3k wob, 9 max gas, 9.3MW, 9.8 ECD p/u=155k, s/o=105k, rt=125k, dbl back ream connection, madd pass
all slide >20', hi-vis sweep every 500' or as needed.
Pump 30bbl hi-vis sweep @3871' w/washing dwn, back on time w/10% increase in cuttings.
SPR's @3830'md/3358'tvd w/9.4ppg
pmp #1: 20stk/215psi, 30/240, 40/290
pmp #2: 20stk/205psi, 30/240, 40/285
Drill/slide f/4167' t/4540.0', 460gpm, 1260psi, 50rpm, 8-10k trq, 1-3k wob, 642 max gas, 9.1MW, 9.8 ECD p/u=165k, s/o=110k, rt=125k, dbl back ream connection, madd
pass all slide >20', hi-vis sweep every 500' or as needed.
Pump 30bbl hi-vis sweep @4360', back 8.3bbls late w/50% increase in cuttings.
Report Number
17
Report Start Date
8/8/2025
Report End Date
8/9/2025
Operation
Drill/slide f/4540' t/4923', 480gpm, 1450psi, 70rpm, 11-12k trq, 2-4k wob, 642 max gas, 9.3MW, 10.1 ECD p/u=185k, s/o=110k, rt=135k, 642 max gas, dbl back ream
connection, madd pass all slide >20', hi-vis sweep every 500' or as needed.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 5/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Take survey on bottom, circ. B/U x3 w/480gpm, 1360psi, 70rpm, 10-13k trq.
Flow check-static, POOH f/4923' t/3790', monitor fill on the TT.
Monnitor for static loss=1.4bph. Test #3 MP t/3000psi-good.
RIH f/3790' t/4923', wash dwn last std, no fill. Monitored displacement on the TT.
Drill/slide f/4923' t/5397', 480gpm, 1429psi, 80rpm, 10-15k trq, 2-3k wob, 9.3MW, 9.82 ECD p/u=200k, s/o=115k, rt=145k, dbl back ream connection, madd pass all slide
>20', hi-vis sweep every 500' or as needed. Obtain SPR's.
Swep hole @4977',back 265stks late w/30% increase in cuttings.
Drill/slide f/5397' t/5580', 480gpm, 1547psi, 65rpm, 10-12k trq, 2-3k wob, 9.3MW, 10.0ECD, 875 max gas, p/u=200k, s/o=115k, rt=145k, dbl back ream connection, madd
pass all slide >20', hi-vis sweep every 500' or as needed. Swep hole @5475',back 378stks late w/40% increase in cuttings.
Loss flow w/backreaming f/37% t/2%, back off pumps and rotary
Circ. @ reduced rate @150gpm, 330pso, 2%flow, stage up pmp t/215gpm, 465psi, 2%flow, pump 35bbl/50ppb LCMpill, going to make a connection and attempt t/drill
ahead and let cuttings fill loss zone.
Drill/slide f/5580' t/5700', 442gpm, 1471psi, 50rpm, 10-11k trq, 2-8k wob, 9.3MW, 10.0ECD, 240max gas, p/u=210k, s/o=120k, rt=145k, dbl back ream connection, madd
pass all slide >20', hi-vis sweep every 500' or as needed.
Pmp 10bbl/50ppb LCM sweep after connection. Reciprocate/pmp40bbl/100ppb LCM, chase w/15bbl/50ppb LCM and displace pipe @report time.
Report Number
18
Report Start Date
8/9/2025
Report End Date
8/10/2025
Operation
Pmp 10bbl/50ppb LCM sweep after connection. Reciprocate/pmp40bbl/100ppb LCM, chase w/15bbl/50ppb LCM and displace pipe w/15bbl over to clear tools of LCM
@150gpm, 400psi.
POOH f/5700' t/5460', above estimated loss zone.monitoring fill on the TT.
Monitor well for static loss rate=12bph loss.
POOH f/5460' t/1520', monitoring fill on the TT. Lost 106bbl over calculated displacement, Total mud lost =592bbls.
Service rig floor equipment, Block and TDS. Trouble shoot ESD f/TDS VFD house. Monitor well on the TT, static loss rate=4bph. Rebuild mud system (908bbls), expedite
mud products on boat.
TIH slow f/1520' t/1804', stage up pmps f/100gpm, 189psi, t/450gpm, 975psi w/no losses.
Cont. TIH f/1804' t/3601',monitor displacement on the TT.
Fill pipe and circ.OH volume, staging up pmps f/100gpm, 275psi to 400gpm, 925psi w/no losses.
Cont. TIH slow f/3601' t/5679', monitoring displacement on the TT.
Fill pipe and Circ. B/U staging up pmps f/140gpm, 465psi to 375psi, 945psi, 20rpm, 12-13k trq, rot/recip..
Drill/slide f/5700' t/5895', w/pump 45bbl50ppb Blitz LCM pill, 450gpm, 1460psi, 50rpm, 10-12k trq, 2-8k wob, 9.6ECD/9.3ppg, 48max gas, p/u=210k, s/o=120k, rt=145k,
dbl back ream connection, 12bbl/50ppb LCM pill every connection or as needed.
Distance t/plan: 24.67', 24.67'high, 2.99'low.
Report Number
19
Report Start Date
8/10/2025
Report End Date
8/11/2025
Operation
Drill/slide f/5895' t/6185', 450gpm, 1500psi, 50rpm, 14-18k trq, 6-14k wob, 9.6ppg MW, 10.1ECD, p/u-220k, s/o=125k, rt=160k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Pumped 20bbl hi-vis sweep @6060', back 580stks late w/30% increase cuttings.
Drill/slide f/6185' t/6323', 460gpm, 1561psi, 80rpm, 17-18k trq, 2-3k wob, 9.6ppg MW, 10.23ECD, p/u-210k, s/o=130k, rt=160k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Drill/slide f/6323' t/6568', 453gpm, 1598psi, 70rpm, 13.5-15.5k trq, 2-3k wob, 9.6ppg MW, 10.32ECD, p/u-220k, s/o=125k, rt=165k. Dbl backream every std, madpass
slide >20ft, sweep hole every 500' or as needed.
Drill/slide f/6568' t/6709', 453gpm, 1598psi, 70rpm, 13.5-15.5k trq, 2-3k wob, 9.6ppg MW, 10.32ECD, p/u-220k, s/o=125k, rt=165k. Dbl backream every std, madpass
slide >20ft, sweep hole every 500' or as needed.
Pump 30bbl hi-vis sweep @3709', rot/recip. w/460gpm, 1495psi, 70rpm, 12-15k trq, 9,7ppg, 10.4ECD.
Sweep back 400 late w/10% increase in cuttings. Shut dwn pump and pump up survey on btm. Get SPR's.
Short trip f/6709' t/5762', monitoring fill on the TT.
Report Number
20
Report Start Date
8/11/2025
Report End Date
8/12/2025
Operation
Perform mad passes missed during loss circ., f/5752' t/5680' and f/5617' t/5587', cont. circ. B/U x4 w/450gpm, 1430psi, 50rpm, 12-16k trq, 9.7ppg, 10.4ECD.
TIH f/5587' t/6709', wash dwn last std. w/450gpm, 1500psi, 50rpm, 12-16k trq, monitored displacement on the TT.
Drill/slide f/6709' t/6876', 450gpm, 1500psi, 80rpm, 18-20k trq, 4-6k wob, 10.0ppg MW, 10.9ECD, p/u-250k, s/o=130k, rt=165k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Pumped 30bbl hi-vis sweep @6709', back 340stks late w/20% increase cuttings.
Drill/slide f/6876' t/7276', 450gpm, 1720psi, 50rpm, 18-23k trq, 4-7k wob, 10.0ppg MW, 10.9ECD, p/u-260k, s/o=125k, rt=175k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Pumped 30bbl hi-vis sweep @6709', back 340stks late w/20% increase cuttings.
Pumped 20bbl hi-vis sweep @7198', back 300stks late w/25% increase cuttings.
Pump hi-vis sweep and circ. out trying to loswer ECD f/10.9EMW, w/450gpm, 1650psi, 60rpm, 21-24k trq, sweep came back 366stks late w/no increase in cuttings.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 6/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drill/slide f/7276' t/7368', 450gpm, 1636psi, 70rpm, 21-24k trq, 4-7k wob, 10.1ppg MW, 10.9ECD, p/u-260k, s/o=130k, rt=175k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Drill/slide f/7368' t/7580', 450gpm, 2020psi, 62rpm, 16-18k trq, 4-8k wob, 10.3ppg MW, 11.29ECD, p/u-260k, s/o=130k, rt=175k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Report Number
21
Report Start Date
8/12/2025
Report End Date
8/13/2025
Operation
Drill/slide f/7580' – t/7620’, 450gpm, 2020psi, 62rpm, 21-24k trq, 6-10k wob, 10.3ppg MW, 11.29ECD, p/u-270k, s/o=130k, rt=175k. Dbl backream every std, madpass
slide >20ft, sweep hole every 500' or as needed.
Trouble shoot pump pressure loss. Checked all surface equipment. Identify string had washout.
TOH f/7620’ – t/5147’. Found washout on joint @ 5149’. L/D bad jt and replace with new jt.
Tested MWD equipment and circulate well clean, 450gpm, 1575psi, 50 rpm, 10-12k trq, 10.3ppg MW, 11.22ECD
TIH f/5178’ – t/7372’. Wash and ream f/7372' – t/7620', 450gpm, 1865psi, 70rpm, 18-21k trq.
Drill/slide f/7620’ – t/7734’, 450gpm, 1950psi, 70rpm, 20-24k trq, 3-8k wob, 10.3ppg MW, 11.16ECD, p/u-270k, s/o=130k, rt=175k. Dbl backream every std, madpass slide
>20ft, sweep hole every 500' or as needed.
Perform clean up circulation. Pumped 30 bbl high-vis sweep @ 7734’, back 310 stks late w/ 100% increase in cuttings.
Note: Circulate additional to get 10.3 ppg in/out.
Perform flow check, no flow. Attempt to TOH on elevators, no success. BROOH f/7734’ – t/7089’. 450gpm, 1650psi, 70rpm, 18-24k trq. Pump out of hole f/7089’ – t/6429’.
450gpm, 1650psi
TOH on elevators f/6429’ – t/1535’. Monitoring hole fill w/ trip tank. Pulled slick back into shoe.
Clean and clear rig floor after wet TOH.
Service Rig: Grease crown, draw works, ST-80 and top drive. Perform daily top drive checklist.
Report Number
22
Report Start Date
8/13/2025
Report End Date
8/14/2025
Operation
TIH f/1521' – t/5021', filling pipe every 20 stds. Monitoring displacement on trip tank.
Note: Had static loss rate of 4 bbls/hr while performing rig service.
Circ/Cond mud, cutting mud wt back from 10.5ppg to 10.4ppg. Staged pumps up to 450gpm,1550psi, 50rpm, 8-10K trq.
TIH f/5021' – t/7657', filling pipe every 20 stds. Monitoring displacement on trip tank.
Wash down last std f/7657’ – t/7735’. No fill observed.
Circ/Cond mud, cutting mud wt back to 10.4ppg. Staged pumps up to 450gpm,1875psi, 60rpm, 12-16K trq.
Pumped 30 bbl high-vis marker sweep @ 7735’, back 578 stks late w/ 100% increase in cuttings.
Perform flow check, no flow. TOH on elevators f/7735’ – t/5491’. Monitoring hole fill w/ trip tank.
Break circulation @ 5491' and pump 45 bbls of 50 ppb LCM pill and spot outside of pipe.
Perform flow check, no flow. TOH on elevators f/5491’ – t/5021’. Pumped dry job and TOH f/5021’ – t/189’. Drop 2.41” drift on last 18 stds. Monitoring hole fill w/ trip tank.
Note: Began testing choke manifold offline @ 23:00 hrs, 2 of 12 test completed.
Hold PJSM with Halliburton MWD, DD and rig crew for unloading radioactive sources. Unload sources and plug in to download data and turn tools off. L/D directional BHA
#4. Break out bit and L/D motor.
Note: Bit Grade As: 1-1-PN-A-X-1-NO-TD
Clean, clear and organize rig floor. Remove Halliburton handling tools.
R/U hose to drain stack. M/U wear bushing retrieval tool, pull wear bushing.
Build test assembly and set test plug. R/U testing equipment and lines. Grease choke manifold. Fluid pack lines and manifold.
Report Number
23
Report Start Date
8/14/2025
Report End Date
8/15/2025
Operation
Test 13 5/8” BOP w/ 5” DP as per Hilcorp test procedure, 250/3000 psi for 5/5 min. Test 3-8 completed (8 of 11).
L/D 5” test assembly and M/U 4.5” test assembly.
Attempt to perform draw down test. Accumulator tri-plex pump bearing on gear end went out. Mobilize new pump from onshore warehouse and change out. Attempt to
pressure up with new accumulator tri-plex pump, leaking around suction cap. Change out gaskets and caps, still leaking. Decision made to swap fluid ends.
Note: Well static loss rate of 2 bbls/hr.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 7/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Perform accumulator draw down test. R/U 4.5” test assembly and perform finial 3 test.
Tested all BOP components t/250/3000psi f/5min. on chart as per AOGCC/Hilcorp policy w/5" and 4 1/2” test jt and water (Test 3C-6 w/5”, test 9-11 w/4 ½”). Annular,
2-7/8 x 5.5 variable rams, blind rams, HCR choke and kill, Manual choke and kill, CMV 1 thru 18, 2 FOSV and 1 Dart, UKV, LKV. Tested gas alarm system, Accumulator
draw down test.
Accumulator test: Closing times:
Initial pressure: 3050psi Annular=12sec.
Final Pressure: 1600psi TPR=10sec. LPR=10sec.
200psi attained: 22sec. Blind rams: 10sec.
Full recovery: 194sec. Choke HCR=1sec.
NO2 Bottle avg.: 2150psi Kill HCR= 1sec.
Test #2-2B: Fail/Pass due to air in system.
Test #3-3B: Fail due to air in system.
Note: Changed accumulator tri-plex pump.
All tests witness waved by AOGCC Representative Jim Regg.
R/D all BOP testing equipment. Pull test plug and B/O all X-O from test jts. Drain stack and fill with mud. Well static loss rate of 2 bbls/hr.
Install wear bushing. R/U Parker power tongs and liner running tools. M/U FOSV to X-O for 4.5” liner. R/U fill up line
PJSM w/ Parker, Baker and rig crew for running 4.5” liner.
TIH w/ 4.5” 12.6# GB CD Butt, P/U Shoe Jt, Float Jt, and L/C Jt. and Baker Lock. Check floats.
TIH w/ 4.5” 12.6# GB CD Butt f/124’ – t/1599' as per tally. Filling up every 10 jts. Monitoring displacement on trip tank.
Change out elevators, install X-O and 10’ pup to circulate and rotate.
Stage pumps up and establish parameters to 5 bpm w/140 psi. Establish rotating parameters, 10 rpm w/450 trq, 20 rpm w/500 trq, 30 rpm w/540 trq. P/U wt 60K, S/O wt
60K. Circulate Btms Up.
L/D circulating assembly. Change out elevators to continue running liner.
TIH w/ 4.5” 12.6# GB CD Butt f/1599’ – t/1910’ as per tally. Filling up every 10 jts. Monitoring displacement on trip tank.
Report Number
24
Report Start Date
8/15/2025
Report End Date
8/16/2025
Operation
TIH w/ 4.5” 12.6# GB CD Butt f/1910’ – t/3723’ as per tally. Filling up every 10 jts. Monitoring displacement on trip tank.
Change out elevators, install X-O and 10’ pup to circulate and reciprocate.
Stage pumps up and establish parameters to 5 bpm w/275 psi. Circulate Btms Up @ 3723’.
L/D circulating assembly. Change out elevators to continue running liner.
TIH w/ 4.5” 12.6# GB CD Butt f/3723’ – t/5883’ as per tally. Filling up every 10 jts. Monitoring displacement on trip tank.
Change out elevators, install X-O and 10’ pup to circulate and reciprocate.
Stage pumps up and establish parameters to 5 bpm w/387 psi. Circulate Btms Up @ 5883’.
L/D circulating assembly. Change out elevators to continue running liner.
TIH w/ 4.5” 12.6# GB CD Butt f/5883’ – t/6202’ as per tally. Filling up every 10 jts. Monitoring displacement on trip tank.
Change out elevators. P/U SLZXP packer and seal assembly. Fill liner tieback sleeve w/ “XANPLEX”. Wait 30 mins for fluid to set up.
TIH w/ Liner on 5” DP to 6342’. Circulate tubing capacity @ 5 bpm w/430 psi. Establish rotating parameters, 10 rpm w/3550 trq, 20 rpm w/3700 trq, 30 rpm w/3800 trq.
P/U wt 135K, S/O wt 80K.
TIH w/ Liner on 5” DP f/6342’ – t/7663’. Monitor displacement on trip tank.
Wash down f/7663' – t/7738' w/ 5 bpm, 550 psi. Tagged w/ 5K down. Establish rotating parameters, 10 rpm w/5400 trq, 20 rpm w/6100 trq, 30 rpm w/6600 trq. P/U wt
165K, S/O wt 100K, ROT wt 125K. Circulate Btms Up.
Note: Unable to rotate when not reciprocating pipe.
P/U and M/U Baker cement head to string. Install high pressure cement lines to head and secure.
PJSM w/ Fox and rig crew. Fox pump 10 bbls of water to clear lines. Test lines to 1000/ 4750 psi for 5 mins, no drop in pressure. Rig pump 25 bbls 12 ppg FMP spacer.
Mix and pump 418 bbls of 12.5 lead cement @ 22:50. Mix and pump 40 bbls of 15.3 ppg tail cement. Shut down, close TIW, open Lo-torque to overboard line and flush
through cement head w/ water. Close Lo- torque and open TIW. Drop plug and displace with rig pumps @ 4.5 bpm w/995 psi, slow rate to 2 bpm 20 bbls prior to bumping
plug. Bump plug @ 1370 stks (75 stks early, 6 bbls). 1000 psi FCP. Pressure up to 1550 psi and hold for 5 mins. Bleed pressure off and check float for 5 mins, Float
good.
Note: Had good returns during lead and partial returns during tail. Lost complete returns after 700 stks during displacement. Lost 169 bbls total. Stopped reciprocating
pipe after 286 bbls of lead pumped.
Set SLZXP packer as per Baker @ 1485’. Packer shear @ 2250 psi, neutralized @ 3030 psi. Held 4000 psi for 2 mins. Bleed pressure off to 700 psi, P/U 4’ and saw free
travel.
Circulate 2 surface to surface, 2200stks, @ 6 bpm w/320 psi, 20 rpm w/450 trq. Saw trace cement in returns @ 850 stks. Take returns overboard. Dumped 182 bbls of
cement contaminated mud.
R/D cement and wash up lines. Drain stack. Function all BOP components and flush stack with FIW.
R/D Baker cement head and circulating equipment.
Drop wiper ball and circulate surface to surface. Take returns overboard. Dumped 98 bbls of mud. No sign of cement.
Prepare rig floor to lay down DP. L/D 5” drill pipe and running tool f/1510’ – t/surface, drift with wiper ball and clean threads. Monitoring hole fill on trip tank.
Report Number
25
Report Start Date
8/16/2025
Report End Date
8/17/2025
Operation
L/D 5” drill pipe and running tool f/1094’ – t/surface, drift with wiper ball and clean threads. Monitoring hole fill on trip tank.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 8/8
Well Name: NCIU A-21A
Report Printed: 9/22/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Test liner to 3000 psi for 10 min. Pumped 3.1 bbl in, 2.5 bbl returned.
P/U & M/U polish mill assembly w/ Baker and TIH t/1455'. Monitoring displacement on trip tank.
Wash f/1455' – t/1517' @ 5 bpm w/250 psi, Tag TOL @ 1485' w/5k down and Polish Seal Bore @ 30 rpm 550k torque as per Baker to 1517', P/U=70k, S/O=70k.
Circulate Btms Up @ 5 bpm w/ 250 psi.
R/U circulating hose and assembly for reverse circulating. Reverse circulate w/sea water displacing 10.3 wbm @ 1485' staging pu mps up to 5 bpm 425 psi. 118 bbls
reversed.
Flush through choke manifold and cement hose. Circulate surface to surface w/sea water @ 6 bpm w/280 psi.
Check for no flow, well U-tubing. Circulate Btms Up @ 7 bpm w/ 280 psi. Monitor well and no longer U-tubing.
Prepare rig floor to lay down DP. L/D 5” drill pipe and polish mill f/1518’ – t/1329’, drift with wiper ball and clean threads. Monitoring hole fill on trip tank.
Crane shut down due to high winds, Clean and organize rig floor.
L/D 5” drill pipe and polish mill f/1329’ – t/surface, drift with wiper ball and clean threads. Monitoring hole fill on trip tank.
L/D 5” DP and HWDP from derrick utilizing mouse hole. Total of 190 jts of 5” DP and 20 jts of 5” HWDP L/D
Drain stack. TIH and retrieve wear bushing. L/D wear bushing and tool.
P/U BOP wash out tool, flush stack and well head profile. L/D tool and stand of HWDP.
Backload workboat with 5” DP, HWDP and Sperry tools. Clean mud pits, shakers and rig floor.
R/U Parker casing running tools and equipment.
PJSM w/ Parker, Baker and rig crew for running 4.5” upper completion.
Report Number
26
Report Start Date
8/17/2025
Report End Date
8/18/2025
Operation
P/U landing jt and hanger. Make dry run to confirm load shoulder. L/D landing jt and hanger. Continue to dump and clean pits.
P/U and M/U seal assembly as per Baker. TIH w/ 4.5” 12.6# IBT production tubing f/surface – t/1092’ as per tally.
P/U and M/U Baker Onyx-5 SSSV, Install control line. Test to 5000 psi, bleed down to 4500 psi. Open pressure @ 2900 psi, close 800 psi. Function 3 times.
TIH w/ 4.5” 12.6# IBT production tubing f/1092’ – t/1505’ as per tally. Installed 11 stainless steel bands.
Change elevators and M/U circulating assembly. Hook up high pressure line.
Break circulation @ 1 bpm w/85 psi. Indication of stung into seals, pressure increase to 135 psi. Continue to slack off to no go @ 1520’.
L/D circulating assembly and 4 jts of 4.5” tubing. P/U and space out with pup jts. P/U tubing hanger and landing jt. Terminate SSSV control line into hanger. Pressure up
and open SSSV with 3200 psi, pressure up to 4500 psi, no leaks in hanger terminations.
Drain BOP stack and land out hanger. Test hanger seals to 5000 psi for 15 mins, good test. Set hanger w/ 6 turns to left, then 3 turns to the right. Pull test to 40K.
R/U test assembly, manifold and lines. Test tubing to 3000 psi for 30 mins, good test. Test IA and tubing to 3000 psi for 30 mins, good test.
R/D test equipment. Back out and L/D landing jt and hanger running tool.
Retrieve T-bar from derrick, Set TWC in tubing hanger. Secure T-bad back in derrick.
Clean and clear rig floor of casing running equipment, subs and X-O. Clean pollution pan of solids. Blow down mud lines to rig floor.
N/D bell nipple and 36” adapter. Begin breaking bolts f/ wellhead – t/Btm of BOP. N/D kill line. Remove Koomey lines from HCRs. Remove flow line. N/D BOPs from riser
and trolly to Aft. N/D riser and L/D. Remove mousehole, V-Door and walkways on HAK deck.
Remove wellhead room hatch and lower production tree onto wellhead. N/U production tree to wellhead. N/U safety valve to production tree.
Field: North Cook Inlet Unit (NCIU)
Sundry #:
State: ALASKA
Rig/Service: 151
Page 1/1
Well Name: NCIU A-21A
Report Printed: 9/23/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:508832019901000 Field Name:North Cook Inlet Unit (NCIU)State/Province:ALASKA
Permit to Drill (PTD) #:225-075 Sundry #:325-449 Rig Name/No:
Jobs
Actual Start Date:8/21/2025 End Date:
Report Number
1
Report Start Date
8/20/2025
Report End Date
8/21/2025
Last 24hr Summary
Fox Crew arrived at 18:00hr, Orientate and PJSM, Offload M/V Titan with CT eq. R/u CTU #9 and eq. N/u Riser and BOP's, P/u Injector head and Lub, stab pipe,
cut off 20' of Coil. Prepare to M/u BHA at report time.
Report Number
2
Report Start Date
8/21/2025
Report End Date
8/22/2025
Last 24hr Summary
IFO, M/u BHA 1.5" wash nozzle, Stab on well, Test BOP's per sundry 250/3500psi. RIH tag bottom at 7596'ctm. Circulate well f/drilling mud t/FIW. POOH. R/u EL,
P/u Lube and tools (CBL) RIH tag bottom @ 7640', logged CBL passes t/top of production liner. POOH R/d EL, Sent CBL to town. P/u IH and lube, M/u BHA, (1.5"
wash nozzle) PT 250-3500psi. Unload IA with gas Lift. RIH tag GLM at 1399', trying different parameters to pass through GLM at report time.
Report Number
3
Report Start Date
8/22/2025
Report End Date
8/23/2025
Last 24hr Summary
IFO, POOH add 5' mandrel to BHA. OAL 12.5'. Stab on well PT 250-3500psi. RIH no issue running through GLM, Tag btm @ 7597'. Blow well dry with N2. Return
114bbls, Cal Vol 115bbls. POOH,Trap 1955psi on Tbg. R/d CTU #9 load on boat and send to beach. Arrange deck. Spot equipment. MIRU AK E-Line. Perforate
Beluga Sa zone 7460' to 7465'. Continue perforating.
Report Number
4
Report Start Date
8/23/2025
Report End Date
8/24/2025
Last 24hr Summary
IFO, Continue Perforating with AK-EL, Perforated BEL_Qb sands (7286'-7316'), BEL_Qa sands (7162'-7193'), BEL_Pb sands (7123'-7126'), BEL_Pa sands (7114'-
7118'), BEL_O sands (7007'-7020'), BEL_Nb sands (6957'-6971'), BEL_Na sands (6943'-6948'), BEL_M sands (6905'-6917'). Turn well over to production to flow
test.
Report Number
5
Report Start Date
8/24/2025
Report End Date
8/25/2025
Last 24hr Summary
IFO, continue flow testing well. P/u Lube and Tools, PT 250-3500psi. RIH with GPT to 7530', pulled GPT w/well shut in, found fluid 7300'. RBIH t/7500', pulled GPT
log w/well flowing, locate fluid 6700'. SI and wait for TP to build 1450psi. Logged GPT f/7500', found fluid level at 6820'. Perforated BEL L sands (6771'-6777').
BEL_Kb sands (6739'-6744'), BEL_Ka sands (6724'-6733'), BEL_Jb sands (6631'-6636'), BEL_Ja sands (6557'-6561'), BEL_I sands (6514'-6518'). Turn well over
to production to flow test.
Report Number
6
Report Start Date
8/25/2025
Report End Date
8/26/2025
Last 24hr Summary
Flow well
Report Number
7
Report Start Date
8/26/2025
Report End Date
8/27/2025
Last 24hr Summary
IFO, MIRU AK EL. P/u Lube and tools, PT 250-3500psi, RIH wGPT, tag fill at 7540', well flowing at 90psi, rate 2.7, log f/ 7540 t/6400', Choked well back t/ 700psi
rate at 1.1M. RBIH tag 7540' log GPT t/6400', POOH, P/u gun #1, RIH make correlation pass at report time.
Report Number
8
Report Start Date
8/27/2025
Report End Date
8/28/2025
Last 24hr Summary
IFO, PJSM and approve PTW, with well flowing, perforate BEL Ge sands (6242'-6247'), BEL Gd sands (6216'-6223'), BEL Gb sands (6174'-6194'), BEL_Ga sands
(6150-6156')', BEL_Fc sands (6128'-6131'), BEL_Fb sands (6101'-6105'), BEL_Fa sands (6074'-6080'), BEL_Ec sands (6027'-6046'), BEL_Eb sands (5974'-
5981'), BEL_Ea sands (5888'-5913'), BEL_Dc sands (5854'-5868'), BEL_Db sands (5840'-5843'), BEL_Da sands (5812'-5815'). Prepping BEL_Cd and BEL_Cc
guns at report time.
Report Number
9
Report Start Date
8/28/2025
Report End Date
8/29/2025
Last 24hr Summary
IFO, PJSM, with well flowing preforated BEL_Cd sands (5679'-5694'), BEL_Cc sands (5666'-5672'), BEL_Cb sands (5656'-5661'), BEL_Ca sands (5644'-5647'),
BEL_Bc sands (5595'-5599'), BEL_Bb sands (5573-5578'), BEL_Ba sands (5561'-5568'), BEL_Ab sands (5441-5454'), BEL_Aa sands (5395'-5414'). Turn well
over to production.
Report Number
10
Report Start Date
8/29/2025
Report End Date
8/30/2025
Last 24hr Summary
IFO. PJSM & PTW. PT 250/3500 PSI. Test good. RIH w/ GPT log. Log Upper & Lower Beluga sands. POOH. RDMO AK EL.
Page 1/1
Well Name: NCIU A-21A
Report Printed: 9/22/2025
WellViewAdmin@hilcorp.com
Casing
Production
Wellbore
Wellbore Name:
Sidetrack 1 Total Depth of Wellbore (ftKB):
7,580.00 Original KB/RT Elevation (ft):
RKB to GL (ft): KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Production Run Date:
8/15/2025 Set Depth (ftKB):
7,724.00
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf):
165.0 Block Weight (1000lbf):
45.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
20.50 Ft/Min (ft/min):
6.28
Run Job:
251-00157 NCIU A-21A Drilling, Drilling -
Drilling, 7/23/2025 18:00
Set Depth (ftKB):
7,724.00 Set Depth (TVD) (ftKB):
6,600.7
Centralizer Detail:
120 total
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 SLZXP Liner Top Pkr 4 1/2 3.96 17.00 L-80 NC50 34.59 1,521.89 1,487.30
53 Liner Joints 4 1/2 3.96 12.60 L-80 GBCD 2,110.21 3,632.10 1,521.89
1 Pup Jt 4 1/2 3.96 12.60 L-80 GBCD 10.29 3,642.39 3,632.10
25 Liner joints 4 1/2 3.96 12.60 L-80 GBCD 989.61 4,632.00 3,642.39
1 PUP Jt 4 1/2 3.96 12.60 L-80 GBCD 10.29 4,642.29 4,632.00
25 Liner joints 4 1/2 3.96 12.60 L-80 GBCD 996.91 5,639.20 4,642.29
1 RA Tag 4 1/2 3.96 12.60 L-80 GBCD 10.28 5,649.48 5,639.20
25 Liner joint 4 1/2 3.96 12.60 L-80 GBCD 988.82 6,638.30 5,649.48
1 RA Tag 4 1/2 3.96 12.60 L-80 GBCD 10.26 6,648.56 6,638.30
24 Liner joints 4 1/2 3.96 12.60 L-80 GBCD 950.63 7,599.19 6,648.56
1 Liner Joint 4 1/2 3.96 12.60 L-80 GBCD 39.63 7,638.82 7,599.19
1 Baffle Adapter 4 1/2 3.96 12.60 L-80 GBCD 1.10 7,639.92 7,638.82
1 Liner Joint 4 1/2 3.96 12.60 L-80 GBCD 42.03 7,681.95 7,639.92
1 Float Collar 4 1/2 3.96 12.60 L-80 GBCD 1.31 7,683.26 7,681.95
1 Liner joint 4 1/2 3.96 12.60 L-80 GBCD 39.29 7,722.55 7,683.26
1 Shoe 4 1/2 3.96 12.60 L-80 GBCD 1.45 7,724.00 7,722.55
Page 1/1
Well Name: NCIU A-21A
Report Printed: 9/22/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Production, 7,722.00ftKB
Wellbore
Original Hole, NCIU A-21
Job
251-00157 NCIU A-21A Drilling, Drilling -
Drilling, 7/23/2025 18:00
Cementing Start Date
8/15/2025
Cementing End Date
8/16/2025
Top Depth (ftKB)
1,487.0
Cement Stages
Stage Number: 1
Description
Liner Cement
Top Depth (ftKB)
1,487.0
Bottom Depth (ftKB)
7,734.0
Top Measurement Method
Volume Calculations
Pump Start Date
8/15/2025
Cement in Place At
8/16/2025
Final Circulating Pressure (psi)
1,000.0
Plug Bump Pressure (psi)
1,550.0
Full Return?
No
Returns During Job (%)
80
Volume to Surface (bbl) Volume Lost (bbl)
169.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 12.00 25.0 5 rig
Lead Slurry Lead G 1,123 2.10 12.50 420.0 420.0 5 cement
Tail Slurry Tail G 180 1.23 15.30 40.0 40.0 5 cement
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CASING AND LEAK-OFF FRACTURE TESTS
Well Name:NCI A-21 Date:8/22/2024
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Sunderland/Brouillet
Csg Setting Depth:1610 TMD 1562 TVD
Mud Weight:9 ppg LOT / FIT Press =472 psi
LOT / FIT =14.81 Hole Depth =1644 md
Fluid Pumped=2.70 Bbls Volume Back =1.60 bbls
Estimated Pump Output:0.083 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->0
->87070 ->5300
->10 90 20 ->10 600
->12 152 62 ->15 900
->14 200 48 ->20 1200
->16 250 50 ->25 1500
->18 270 20 ->30 1800
->20 280 10 ->35 2100
->22 340 60 ->40 2400
->24 370 30 ->45 2700
->26 390 20 ->50 3000
->28 410 20 ->55 3300
->30 450 40 ->60 3610
->32 470 20 ->61
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0470 ->03610
->1460 ->53595
->2430 ->10 3585
->3406 ->15 3580
->4380 ->20 3580
->5366 ->25 3578
->6351 ->26 3575
->7337 ->27 3575
->8324 ->28 3575
->9312 ->29 3575
->10 301 ->30 3575
->11 291 ->
->12 280 ->
->13 272 ->
->14 263
->15 254
->16 248
0
8 10
12 14 16 18 20
22 24 26 28 30 32
5
10
15
20
25
30
35
40
45
50
55
60
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
470460430406380366351337324312301291280272263254248
3610 3595 3585 3580 3580 357835753575357535753575
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/19/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250919
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF
T40899
BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL
T40900
BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL
T40901
BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf
T40902
KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf
T40903
MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker
T40904
MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper
T40905
MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL
T40906
NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut
T40907
NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf
T40908
ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey
T40909
ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey
T40910
ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log
T40911
PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM
T40912
PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN
T40913
TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift
T40914
Please include current contact information if different from above.
NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.22 13:22:50 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/12/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250912
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP
BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf
BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf
GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf
KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF
MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift
MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift
MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL
MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL
MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch
NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf
END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40
END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40
END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG
END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24
NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG
PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG
PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG
PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT
SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D
ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey
Please include current contact information if different from above.
T40874
T40875
T40875
T40875
T40875
T40876
T40877
T40878
T40879
T40879
T40880
T40881
T40882
T40883
T40884
T40885
T40886
T40887
T40888
T40889
T40890
T40891
T40892
T40893
NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.12 14:33:03 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/05/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-21A
PTD: 225-075
API: 50-883-20199-01-00
FINAL LWD FORMATION EVALUATION LOGS (08/03/2025 to 08/12/2025)
x GR, RES, DEN, NEU (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Data Main Folders:
Please include current contact information if different from above.
225-075
T40854
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.05 11:10:37 -08'00'
From:Rixse, Melvin G (OGC)
To:Eric Dickerman
Cc:Davies, Stephen F (OGC)
Subject:20250822 0906 APPROVAL to perforate A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Date:Friday, August 22, 2025 9:07:58 AM
Eric,
Hilcorp is approved to perforate as describe in Sundry 325-499.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Steve Davies
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Friday, August 22, 2025 3:36 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Mr. Rixse and Mr. Davies,
Please see attached CBL from NCIU A-21A for your review and approval. The target perforation
interval picked for this well has a top at ± 5,392’ md / 4,465’ tvd down to a bottom at ± 7,465’ md
/ 6,363’ tvd. I have also attached the previous correspondence regarding the completion
interval (pool depths, shallowest allowable perf depth, etc).
If approved, we may have eline available to begin perforating this afternoon/evening.
Regards,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Thursday, August 21, 2025 9:06 AM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Eric,
We will make it a priority. Thanks for the notice.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Steve Davies
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Thursday, August 21, 2025 8:52 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Good morning Mr. Rixse and Mr. Davies,
Just providing an update on A-21A. We are currently rigging up coiled tubing to circulate the well
out. If operations follow our timeline, we should have the CBL sent to you for review by tomorrow
morning.
Thank you,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Monday, August 18, 2025 5:43 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: Re: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Thank you sir, I will keep you informed of unit arrival to the platform and updated on CBL
timing.
Regards,
Eric Dickerman
Hilcorp - CIO Ops Engineer
307-250-4013
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Monday, August 18, 2025 2:55 PM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at
CBL
Eric,
We will try to get the sundry approved through commissioners today. The conditions
of approval will clearly state AOGCC to review CBL before perforating.
I should be able to give a verbal if needed for you to start the work.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Monday, August 18, 2025 11:41 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: Re: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Mel,
Yes sir, will send the CBL in for AOGCC approval to perforate. Do we have permission to
rig up coil and eline to perform the wellwork steps preceding the perforating? I was
unsure if we were ok to do so without the approved 10-403.
Based on the current timeline we would expect coil and eline to arrive 8/20-21 to
circulate the well out and perform the CBL. Looking to have the CBL to you for review
Thursday/Friday 8/21-22. General steps are:
1. Coil – MIRU, BOP test, circulate drilling mud from well with water. Stand back for
eline.
2. Eline – MIRU, CBL from PBTD to above 1400’. RD. Send CBL to AOGCC for review.
3. Coil – Blow well down with Nitrogen. RDMO.
4. Eline – Perforate pending AOGCC approval of CBL.
Thank you,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Sent: Monday, August 18, 2025 10:47:56 AM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] A-21A PTD225-075 NCIU A-21A Sundry 325-449 - AOGCC to look at CBL
Eric,
I got your message that you hope to perforate NCIU A-21A on 8-20-2025. AOGCC will
need to review the CBL before approving the perf interval. Please send it to Steve, Andy,
and myself, then after our review, I can provide a verbal if adequate cement for
perforating.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain
confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or
federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the
AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Steve Davies, Andy Dewhurst
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Eric Dickerman
CIO
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
ѷ7,724 (proposed)N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Other: Initial Completion,N2
CT Ops
North Cook Inlet Tertiary System Gas Same
ѷ6,627 (proposed)ѷ7,624 (proposed)ѷ6,536 (proposed 2,717psi N/A
CO 68A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
225-075
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21A
Length Size
Proposed Pools:
L-80
TVD Burst
ѷ1,400 (proposed)
8,430psi
MD
1,630psi
6,870psi
384'
ѷ1,554 (proposed)
384'
ѷ1,600 (proposed)
30"
9-5/8"
384'
ѷ1,600 (proposed)
See schematic
ѷ6,324 (proposed)
See schematic
ѷ6,627 (proposed)4-1/2"ѷ7,724 (proposed)
8/13/2025
4-1/2"
LTP & SSSV ѷ1,400 (MD)ѷ1,381 (TVD) &ѷ446 (MD)ѷ446 (TVD)
Perforation Depth MD (ft):
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:21 pm, Jul 30, 2025
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.07.30 13:43:22 -
08'00'
Dan Marlowe
(1267)
325-449
* Service coil BOPE test to 3500 psi. 48 hour notice to AOGCC for opportunity to witness.
* Cement Bond Log to be reviewed by AOGCC. Not approved to perforate until AOGCC provides
written response after their review of CBL.
10-407
(original completion)
A.Dewhurst 19AUG25 DSR-8/13/25MGR18AUG25*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.08.20 08:54:42 -08'00'08/20/25
RBDMS JSB 082025
Initial Completion
Well: North Cook Inlet Unit A-21A
Well Name:NCIU A-21A API Number:50-883-20199-01-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-075
First Call Engineer:Eric Dickerman (907) 564-4061
Second Call Engineer:Casey Morse (907) 777-8322
Maximum Expected BHP:3,380 psi at 6,627’ TVD - 0.51 psi/ft – 10-401 page 34
Max. Potential Surface Pressure: 2,717 psi MPSP -0.1 psi/ft gas grad. to surface – 10-401 page 34
Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool
Applicable Frac Gradient: 0.78 psi/ft using 15.0 ppg EMW – 10-401 page 34
Shallowest Allowable Perf TVD: MPSP/(Frac grad. – Gas grad.) = 2,717 psi / (0.78 – 0.1 psi/ft) = 3,996’ TVD
Brief Well Summary:
Spartan 151 is currently rigging up to drill NCIU A-21A. The primary target is the Beluga sands, with a future
option to test the Sterling sands. The well is planned to sidetrack out of the existing 9-5/8” casing around
1,600’, then drill the 8-1/2” production hole to a target TD of ± 7,724’ MD. The production interval will be
cased with a 4-1/2” production liner. The upper completion is planned to be a 4-1/2” tieback.
Objective:
Initial completion post rig. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD
approval from AOGCC before perforating.
Wellbore information:
x A 9-5/8” x 4-1/2” liner lap test, a 4-1/2” MIT-T, and a 9-5/8” x 4-1/2” MIT-IA will be performed to 3,000
psi on the rig per the approved 10-401.
x An FIT to 14.8 ppg is planned within 20’ – 50’ of the 9-5/8” sidetrack window.
x The well will be completed with a tubing retrievable subsurface safety valve set at ± 400’.
x North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, estimated at 3,705’ MD /
3,267’ TVD from prognosis.
x North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands.
Initial Completion
Well: North Cook Inlet Unit A-21A
Slickline Procedure:
1. MIRU Slickline.
2. Pressure test PCE to 250 psi low / 3,500 psi high.
3. Drift to PBTD.
4. RDMO Slickline.
Eline Procedure: (if slickline is able to drift to PBTD)
5. MIRU Eline.
6. Pressure test PCE to 250 psi low / 3,500 psi high.
7. Log CBL from PBTD to top of production liner (estimated at 1,400’).
a. Submit CBL to AOGCC for approval prior to perforating.
8. RDMO Eline.
Coiled Tubing Procedure:
9. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
10. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48hr witness notification for BOP test.
11. MU cleanout BHA.
12. RIH to PBTD and circulate the well from drilling mud to filtered inlet water.
13. If Eline is unable to log CBL, RIH with CBL toolstring in carrier then log from PBTD to top of production
liner (estimated ± 1,400’). Submit CBL to AOGCC for approval.
14. RIH and blow well dry with nitrogen.
15. RDMO CTU.
ELine Perf procedure
16. MIRU Eline and Nitrogen package.
17. Pressure test PCE and N2 treating iron to 250 psi low / 3,500 psi high.
18. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC
before perforating.
19. Perforate target gas sands in the North Cook Inlet Unit Tertiary Systems Gas Pool per Reservoir
Engineer/Geologist.
a. Top pool from prognosis = 3,705’ MD / 3,267’ TVD.
b. Bottom pool = deeper than TD.
c. Use Nitrogen to pressurize wellbore to target shooting pressure.
20. RDMO Eline and Nitrogen.
CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water)
21. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,500 psi high.
22. Pressure up on tubing to displace water back into formation.
23. MIRU Eline.
24. Pressure test PCE to 250 psi low / 3,500 psi high.
25. Set 4-1/2” CIBP or patch to shut off unwanted interval per Operations Engineer.
26. RDMO Eline and Nitrogen.
* NOT APPROVED TO PROCEED WITH PERFORATING UNTIL AOGCC REVIEWS LOGS. - mgr
Initial Completion
Well: North Cook Inlet Unit A-21A
CONTINGENCY Coiled Tubing Cleanout: (if any zone brings in excessive fill and needs to be cleaned out)
27. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
28. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48hr witness notification for BOP test.
29. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per Operations Engineer.
a. Working fluid will be 6% KCl (8.6 ppg).
b. Take returns to surface from the coiled tubing by 4-1/2” annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
30. RIH and blow well dry with nitrogen.
31. RDMO CTU.
Operations:
32. Perform SVS test within 5 days of steady production.
Attachments:
1. Proposed Wellbore Schematic
2. CT BOP Drawing
3. Nitrogen procedure
Updated by JLL 07/29/25
Proposed SCHEMATIC
North Cook Inlet Unit
NCIU A-21A
PTD: 225-075
API: 50-883-20199-01-00
PBTD = ±7,624’ / TVD = ±6,536’
TD = ±7,724’ / TVD = ±6,627’
RKB = 126.6’
A-21
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf ±1,600’ TOW
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” ±1,400’ ±7,724’
4-1/2" Prod Tieback 12.6 L-80 EUE 3.958” Surf ±1,400’
130”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth Item
1 ±446’ SSSV
2 1,008’ ES Cementer
3 ±1,200’ GLM
4 ±1,350’ X Nipple
5 ±1,400’ Liner hanger / LTP Assembly
6 ±1,400’ Seal Stem
7 1,600’ 9-5/8” Whipstock
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 387 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 408 bbls / T – 36 bbls
8-1/2”
hole
2
4
5/6/7
3
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD)
Btm
(TVD)FT Date Status
Tertiary
System
Gas Pool
±3,705’ PBTD ±3,267’ PBTD Future Proposed
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
1
Dewhurst, Andrew D (OGC)
From:Eric Dickerman <Eric.dickerman@hilcorp.com>
Sent:Friday, 15 August, 2025 15:32
To:Dewhurst, Andrew D (OGC)
Cc:Rixse, Melvin G (OGC); Starns, Ted C (OGC); Davies, Stephen F (OGC); Casey Morse
Subject:RE: [EXTERNAL] RE: PTD 225-075, NCIU A-21A, Completion interval
Attachments:NCIU A-21A Field Final FE Data.las; NCIU A-21A Surveys.las
Mr. Dewhurst,
Please see aƩached log data and direcƟonal survey as requested.
Regards,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Friday, August 15, 2025 2:48 PM
To: Eric Dickerman <Eric.dickerman@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Davies, Stephen F
(OGC) <steve.davies@alaska.gov>; Casey Morse <casey.morse@hilcorp.com>
Subject: [EXTERNAL] RE: PTD 225-075, NCIU A-21A, Completion interval
Eric,
To help us with this review, would you please provide the directional survey (.txt, .xlsx, etc.) and the logs
in .las format?
Thanks,
Andy
From: Eric Dickerman <eric.dickerman@hilcorp.com>
Sent: Friday, August 15, 2025 11:49 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Casey Morse <Casey.Morse@hilcorp.com>
Subject: PTD 225-075, NCIU A-21A, Completion interval
Mr. Rixse and Mr. Davies,
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders .
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
2
We called TD in the production interval on NCIU A-21A at 7,734’ md and are currently running production
liner. This email is to communicate and conƱrm the pool top and allowable perf interval as mentioned in the initial
perforation 10-403 submitted on 7/30/25. A log of the production interval and a copy of the 10-403 submitted are
attached. Pending the CBL review on the 4-1/2” production liner, Hilcorp is requesting approval for a target perf
interval with the top at ± 5,392’ md / 4,465’ tvd down to a bottom at ± 7,465’ md / 6,363’ tvd. The calculations are
provided below. Please let me know if you have any questions.
x FIT from 9-5/8” casing window = 14.8 ppg EMW at 1,562’ TVD = 0.77 psi/ft.
x TD = 7,734’ md / 6,610’ tvd.
x Maximum possible surface pressure = 2,717 psi from PTD.
x Shallowest allowable perf TVD = 2,717 psi / (0.77 psi/ft – 0.1 psi/ft) = 4,055’ tvd.
x Top of pool (as drilled) = 3,657’ md / 3,247’ tvd
x Bottom of pool = below TD
Based on the latest drilling plan forward, they are expecting to rig down from A-21A on Sunday, then plan to start
skidding over to A-06. We are working towards having coiled tubing and eline arrive for the post rig work
Monday/Tuesday 8/18-19. Due to deck space on the platform Spartan 151 will not be able to Ʊnish rigging up on A-
06 until coil and eline have Ʊnished A-21A post rig work so we are working to execute that work promptly.
Thank you,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet Unit Field, Tertiary System Gas Pool, NCIU A-21A
Hilcorp Alaska, LLC
Permit to Drill Number: 225-075
Surface Location: 1254' FNL, 982' FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 622' FSL, 1464' FEL, Sec 36, T12N, R10W, SM, AK
Dear Mr. McLaughlin:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this 22nd day of July 2025.
Jessie L.
Chmielowski
Digitally signed by
Jessie L. Chmielowski
Date: 2025.07.22
09:32:50 -08'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 7,724' TVD: 6,627'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 126.6 15. Distance to Nearest Well Open
Surface: x-332001 y-2586725 Zone-4 N/A to Same Pool: 1002' to NCIU A-08
16. Deviated wells:Kickoff depth: 1,600 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 46 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
8-1/2" 4-1/2" 12.6# L-80 GBCD 6,324' 1,400' 1,380' 7,724' 6,627'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
10163'
TVD
384'
3499'
6923'
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
7/26/2025
4317' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
11391'
8328
Cement Volume MD
Driven 384'
5909'9-5/8"1902 sx
Drilling Manager
Sean Mclaughlin
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
5909'
1023 sx
To be plugged
Conductor/Structural 30"384'
Authorized Title:
Authorized Signature:
4-1/2"
Authorized Name:
Production
Liner 5655'
Intermediate
11394'6925'
LengthCasing
6450'
Size
Plugs (measured):
(including stage data)
L - 2294 ft3 / T - 205 ft3
6450'3731'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
18. Casing Program:Top - Setting Depth - BottomSpecifications
3380
GL / BF Elevation above MSL (ft):
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
2717
303' FNL, 432' FWL, Sec 6, T11N, R9W, SM, AK
622' FSL, 1464' FEL, Sec 36, T12N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1254' FNL, 982' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589 / ADL 37831
NCIU A-21A
North Cook Inlet Unit
Tertiary System Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
To be plugged
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 3:57 pm, Jul 09, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.07.09 15:15:03 -
08'00'
Sean
McLaughlin
(4311)
MGR17JULY2025
225-075
* BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC.
* Email casing test and FIT digital data upon completion of FIT.
If FIT is less than 14.8 PPGE call AOGCC PE (907)297-8474
to discuss operational additional operational diligence to assure early influx detection.
50-883-20199-01-00
DSR-7/16/25A.Dewhurst 21JUL25
*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2025.07.22 09:33:05 -08'00'07/22/25
07/22/25
RBDMS JSB 072425
A-21A Drilling Program
Tyonek
Sean McLaughlin
PTD
July 09, 2025
NCI A-21A
Drilling Program
Contents
1. Well Summary.....................................................................................................................................2
2. Management of Change Information................................................................................................3
3. Tubular Program:...............................................................................................................................4
4. Drill Pipe Information:.......................................................................................................................4
5. Internal Reporting Requirements.....................................................................................................5
6. Current Wellbore Schematic.............................................................................................................6
7. Planned Wellbore Schematic (see sundry for decomplete schematic) ...........................................8
8. Drilling Summary...............................................................................................................................9
9. Mandatory Regulatory Compliance / Notifications.......................................................................10
10. BOP N/U and Test.............................................................................................................................12
11. Preparatory Work and Mud Program............................................................................................12
12. Decomplete, Plug parent wellbore...................................................................................................14
13. Set Whipstock, Mill Window...........................................................................................................14
14. Drill 8-1/2” Hole Section...................................................................................................................15
15. Run 4-1/2” Production Liner...........................................................................................................17
16. Cement 4-1/2” Production Liner.....................................................................................................19
17. Wellbore Clean Up & Displacement...............................................................................................22
18. Run Completion Assembly...............................................................................................................22
19. BOP Schematic..................................................................................................................................23
20. Wellhead Schematic..........................................................................................................................24
21. Anticipated Drilling Hazards...........................................................................................................25
22. Jack up position ................................................................................................................................26
23. FIT Procedure...................................................................................................................................27
24. Choke Manifold Schematic..............................................................................................................28
25. Casing Design Information ..............................................................................................................30
26. 8-1/2” Hole Section MASP...............................................................................................................31
27. Plot (NAD 27) (Governmental Sections).........................................................................................32
28. Slot Diagram......................................................................................................................................33
29. Directional Program (wp04) - Attached separately......................................................................34
Page 2 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
1. Well Summary
Well NCI A-21A
Drilling Rig Rig 151
Leg 1
Directional plan wp04
Pad & Old Well Designation Sidetrack of existing well A-21 (PTD#224-086)
Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing Comp
Target Reservoir(s)Beluga A-T
Kick off point 1600’ MD
Planned Well TD, MD / TVD 7724’ MD / 6627’ TVD
PBTD, MD 7624’ MD
AFE Number
AFE Days
AFE Drilling Amount
Work String 4.5” 16.6# S-135 CDS40 or 5” 19.5# S135 NC50
RKB – AMSL 126.63’
MSL to ML 74.1’
Page 3 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
2. Management of Change Information
Date: July 9, 2025
Subject: Changes to Approved Permit to Drill
File #: NCI A-21A Drilling Program
Significant modifications to Drilling Program for PTD will be documented and approved below. Significant
changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward
with work.
Sec Page Date Procedure Change Approved By
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
3. Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Prod
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288
** Liner must overlap casing by at least 100’.
4. Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
or
5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k
4-1/2" 16.6 ppf drill pipe internal capacity ~ 0.01422 bbls/ft - MGR
Page 5 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
5. Internal Reporting Requirements
1. Fill out daily drilling report and cost report.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports.
2. Afternoon Updates
x Submit a short operations update every day to Kenai/CIO Drilling
<KenaiCIODrilling@hilcorp.com>
3. EHS Incident Reporting
x Notify EHS field coordinator.
i. Garrett St. Clair: C: (907) 252-7780
x Spills:
i. Adrian Kersten: C: 907-564-4820
ii. Sean Mclaughlin
x Report ALL spills to the water within 15 minutes.
x Submit Hilcorp Incident report to contacts above within 24 hrs
4. Casing Tally
x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com
5. Casing and Cmt report
x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and
cdinger@hilcorp.com
Page 6 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
6. Current Wellbore Schematic
Page 7 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
Page 8 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
7. Planned Wellbore Schematic (see sundry for decomplete schematic)
Page 9 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
8. Drilling Summary
A-21 is a shut in gas well with all opportunities exhausted. Well planned to be sidetracked to down-space the
producing Beluga formations.
The 4-1/2” tubing will be cut and pulled prior to running a 9-5/8” cement retainer. The parent will be plugged
with cement above and below the retainer. The parent wellbore will be sidetracked and new wellbore drilled
to 7724’. A 4-1/2” L-80 prod liner will be run, cemented, and perforated based on data obtained while drilling
the interval.
The well will be completed with a 4-1/2” gas lift tie-back completion.
Drilling operations are expected to commence approximately July 26, 2025.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
General sequence of operations pertaining to this drilling operation:
Rig
1. Rig 151 will MIRU over Leg 1, Well A-21 (Sundry Ļ)
2. NU BOPE and test to 3000 psi. (MASP 2717psi)
3. Pull 4-1/2” tubing from the PBR at 5766’
4. Set 9-5/8’ 47# cement retainer at 5600’, plug parent well with cement
5. Test 9-5/8” casing to 3000 psi.
6. Set 9-5/8” whipstock at 1600’ and 150L. Swap well to 9.0 ppg LSND mud.
7. Mill window with 20’ of new formation.(Permit To Drill Ļ)
8. Perform FIT to 14.8 ppg EMW
9. PU 6-3/4” motor drilling assembly and TIH to window.
10. Drill 8-1/2” production hole to 7724’ MD, performing short trips as needed
11. RIH w/ 4-1/2” liner. Set liner and cement.
12. Perform liner lap test to 3000 psi.
13. Run 4-1/2” completion.
14. Land hanger and test.
15. ND BOPE, NU tree and test void
Reservoir Evaluation Plan:
1. Production Hole: Triple Combo LWD
Page 10 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
9. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
o The highest reservoir pressure expected is 3380 psi in the Beluga S/T sands (6627' TVD). MASP
is 2717 psi with 0.1psi/ft gas in the wellbore.
o A casing test to 3000 psi is planned after plugging the parent
x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi.
x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized
for well control must be tested prior to the next trip into the wellbore. This pressure test will be
charted same as the 14 day BOP test.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Page 11 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
8-1/2”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 5M Shaffer SL Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 5M Shaffer SL single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 12 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
10. BOP N/U and Test
1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug
2. N/U to 11” 5M
3. N/U 13-5/8” x 5M BOP as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm
cavity)
x 13-5/8” mud cross
x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master
valve”.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
x 11” 5M Clamp hub adapter required
4. Test BOPE.
x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not
build up beneath the TWC. Confirm the correct valves are opened!!!
x Test VBRs on 4.5” and 5” (if using 5” DP)test joints (3000 psi)
x Test Annular on 4.5” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
5. Pull Blanking plug and BPV
11. Preparatory Work and Mud Program
1. Mix 9.0 WBM mud for 8-1/2” hole section.
2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s)
x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422
gpm at 115 spm.
x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps.
Page 13 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
3. 8-1/2” Production hole mud program summary:
x Primary weighting material to be used for the hole section will be barite to minimize solids.
Ensure enough barite is on location to weight up the active system 1ppg above highest
anticipated MW in the event of a well control situation.
x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, and Toolpusher office.
System Type:LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1600’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 11.0
System Formulation: 2% KCL/BDF-976/GEM GP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
DEXTRID LT
PAC L
BDF-976
GEM GP
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROTROL PLUS
SOLTEX
BAROID 41
ALDACIDE-G
0.905 bbl
7 ppb
0.2 ppb (9 pH)
1.0 ppb (as required 18 YP)
1-2 ppb
1 ppb
4 ppb
1.0% by volume
5 ppb (1.7 ppb of each)
5 ppb (1.7 ppb of each)
1.7 ppb
4.0 ppb
2 – 4 ppb
as needed
0.1 ppb
Page 14 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated
BHP’s from formations capable of producing fluids or gas and formations which could require mud
weights for hole stabilization.
5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced
and have the challenge to mitigate lost circulation.
12. Decomplete, Plug parent wellbore
Operation Steps:
1. Pull 4-1/2” tubing from PBR at 5766’.
2. Set wear bushing in wellhead. Ensure ID of wear bushing > 8-1/2”.
3. PU 9-5/8” cement retainer and set at 5600’
4. Pump 50 bbls of 15.3# below the retainer
x ~23bbl to upper CIBP (27bbls excess)
x 4-1/2” CIBP at 6450’
x 4-1/2” CIBP at 8630’ w/ 31’ of cement on top
5. Unsting from retainer and lay in 30 bbls of cement above the retainer (~400’)
6. WOC, Tag cement
7. Pressure test 9-5/8” casing to 3000 psi.
13. Set Whipstock, Mill Window
Operation Steps:
1. Make up the WIS hydraulic set Whipstock.
2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock
assembly
¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly.
¾Avoid sudden starts and stops while running the whipstock.
¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch
the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly
Page 15 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
when releasing the work string to RIH. These precautions are required to avoid any weakening of the
whipstock shear mechanisms and / or to avoid part / preset on the packer.
3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg LOHS.
4. Set the top of the whipstock at ~1600’ MD
x 9-5/8” Collars TBD
Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
5. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 14.8 ppg.
¾**Assuming the kick zone is at TD, a FIT of 14.8 ppg EMW gives a Kick Tolerance volume of 17 bbls with
10.3 ppg mud weight.
6. POOH and LD milling assembly
¾Once out of the hole, inspect mill gauge and record.
¾Flow check well for 10 minutes to confirm no flow:
¾Before pulling off bottom.
¾Before pulling the BHA through the BOPE.
7. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
14. Drill 8-1/2” Hole Section
1. PU 7800’or 4-1/2” or 5”Drill pipe for drilling 8-1/2” hole section
Email casing test and FIT digital data upon completion of FIT. If FIT is less than 14.8 PPGE call AOGCC PE (907)297-8474
to discuss operational additional operational diligence to assure early influx
detection. - mgr
Page 16 PTD July 9, 2025
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2. P/U 6-3/4” Sperry Sun motor drilling assy
x Drill 200’ of rathole prior to picking up LWD to avoid tool damage across the window.
3. Ensure BHA Components have been inspected previously.
4. Drift & caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
5. Ensure TF offset is measured accurately and entered correctly into the MWD software.
6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~450 gpm.
7. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and
drop sections of the wellbore.
8. Primary bit will be the 8-1/2” Hycalog A1. Ensure to have a backup PDC bit available on location.
9. TIH to window. Shallow test MWD on trip in.
10. Circulate well with 9.0 ppg LNSD to warm up mud until good 9.0 ppg in and out.
11. Drill approx. 200’ rat hole to accommodate the LWD assembly. Ream window as needed to assure
there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and
pass through shoe checking for drag.
12. Circulate Bottoms Up until MW in = MW out.
13. Trip to surface to pick up triple combo (DEN, POR, RES).
14. Drill 8-1/2” hole to 7724’ MD using motor assembly.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be
provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal
seams once drilled.
x Keep swab and surge pressures low when tripping.
x Ensure solids control equipment functioning properly and utilized to keep LGS to a
minimum without excessive dilution.
x Adjust MW as necessary to maintain hole stability.
x Ensure mud engineer set up to perform HTHP fluid loss.
x Maintain API fluid loss < 6.
x Take MWD surveys every stand drilled.
x Minimize backreaming when working tight hole
15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for
cement calculations. CBU, and pull a wiper trip back to the window.
Page 17 PTD July 9, 2025
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16. TOH with drilling assembly, handle BHA as appropriate.
15. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure DP crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted and tally verified prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Landing collar pup bucked up.
x Centralizers will be run on 4-1/2” liner
x Ensure proper operation of float shoe & FC.
4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’
x Fill liner while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
Page 18 PTD July 9, 2025
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5. Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not
be set in a connection.
6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make
sure it coincides with the pipe tally.
7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin
enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up.
8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner.
9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
10. M/U top drive and fill pipe while lowering string every 10 stands.
Page 19 PTD July 9, 2025
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11. Set slowly in and pull slowly out of slips.
12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” window prior to going into open hole. Stage pumps
up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
16. Cement 4-1/2” Production Liner
1. Hold a pre-job safety meeting over the upcoming cmt operations.
2. Attempt to reciprocate the casing during cmt operations until hole gets sticky.
3. Pump 15 bbls 12.5 ppg spacer.
4. Test surface cmt lines to 4500 psi.
5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump per below recipe and volume with xx lbs/bbl of loss circulation fiber. Please
independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job
is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase
excess volumes. Cement volume is designed to bring cement to TOL.
7. Displacement fluid will be CLEAN drilling mud. Program displacement volume 108 bbls.Please
independently verify with actual inputs.
Slurry Information:
Page 20 PTD July 9, 2025
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8. Drop DP dart and displace with clean 10.3 ppg WBM.
9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner
wiper plug. Note plug departure from liner hanger running tool and resume pumping at full
displacement rate. Displacement volume can be re-zeroed at this point
10. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes. Reduce pump rate as required to avoid packoff.
11. Bump the plug. Do not overdisplace by more than 2 bbls.
Lead Slurry Tail Slurry
Density 12.5 lb/gal 15.3 lb/gal
Yield 2.1 ft3/sk 1.24 ft3/sk
Mix Water 12.01 gal/sk 5.58 gal/sk
Estimated cement displacement to shoe track top = ((0.01422 * 1400') + ((7724 - 1400- 80) * .0152)) = 94.9 bbls - mgr
Page 21 PTD July 9, 2025
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12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner
13. Bleed pressure to zero to check float equipment.
14. P/U, verify setting tool is released.
15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple.
Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops
rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome
hydrostatic differential at liner top).
16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up
to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up
rate until the sleeve area is thoroughly cleaned.
17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation,
do not re-tag the liner top, and circulate the well clean.
18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP.
19. POOH, LDDP.
Backup release from liner running tool:
20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to
be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that
the tool is in the neutral position. Apply left-hand torque as required to shear screws.
21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the
setting tool.
22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed
slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At
this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to
release collet from the profile.
Ensure to report the following on Wellview:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Page 22 PTD July 9, 2025
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x Note if liner is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com
17. Wellbore Clean Up & Displacement
1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to
perforating.
2. Test liner lap to 3000 psi after cement has reached 500 psi compressive strength. 10 min operational
assurance test.
18. Run Completion Assembly
1. Run 4-1/2” tubing completion assembly to above the liner top
x Tubing will be 4-1/2” L-80 12.6# EUE
x Baker S-5 SSSV to be placed between 400’ and 450’ MD
x 1 live GLM’s will be run at 1200’
x Tripoint X NIP – just above the seal stem
2. Swap the well over to FIW
x Circulate a hi-vis pill followed by a soap train per Baroid
x Circulate FIW until clean-up is satisfactory.
x Leave FIW in the annulus.
3. Space out and land seal bore in tie back sleeve. RILDs.
4.Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min.
5. Install BPV in wellhead.
Page 23 PTD July 9, 2025
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6. ND BOPE, NU tree, test void
7. Rig Down
19. BOP Schematic
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20. Wellhead Schematic
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21. Anticipated Drilling Hazards
Lost Circulation:
Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and
A-01A)
x Maintain sufficient volumes while drill.
x Maintain ability to take on FIW during drilling phase
x If a LC event occurs pumping cement will be the likely remedy
Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition
carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize
solids control equipment to maintain density and minimize sand content. Maintain programmed mud
specs.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
x Minimize swab and surge pressures
x Minimize back reaming through coals when possible
H2S:
H2S is not present in this hole section.
Anticollision:
No close approaches.
Page 26 PTD July 9, 2025
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22. Jack up position
Page 27 PTD July 9, 2025
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23. FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface
pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 28 PTD July 9, 2025
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24. Choke Manifold Schematic
Page 29 PTD July 9, 2025
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Drilling Program
PTD xxxxxx
Page 30 PTD July 9, 2025
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Drilling Program
PTD xxxxxx
25. Casing Design Information
Page 31 PTD July 9, 2025
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PTD xxxxxx
26. 8-1/2” Hole Section MASP
Page 32 PTD July 9, 2025
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27. Plot (NAD 27) (Governmental Sections)
Page 33 PTD July 9, 2025
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Drilling Program
PTD xxxxxx
28. Slot Diagram
Page 34 PTD July 9, 2025
NCI A-21A
Drilling Program
PTD xxxxxx
29. Directional Program (wp04) - Attached separately
!" #
$%%
& $
& $ "
1275
1700
2125
2550
2975
3400
3825
4250
4675
5100
5525
5950
6375
6800
7225True Vertical Depth (850 usft/in)-425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525
Vertical Section at 307.49° (850 usft/in)
1000
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
55006 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
8 0 0 0
8 5 0 0
9 0 0 0
9 5 0 0
1 0 0 0 0
1 0 5 0 0
1 1 0 0 0
1 1 3 9 4
NCIU A-21
9-5/8" KOP
4-1/2" x 8-1/2"
1000
1 5 0 0
2 0 0 0
2 5 0 0
3 0 003 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
7 7 2 4
NCIU A-21A wp04
KOP: 12.3º/100' : 1600' MD, 1553.94'TVD : 150° LT TF
End Dir : 1617' MD, 1567.48' TVD
Start Dir 4º/100' : 1717' MD, 1648.05'TVD
End Dir : 3191.6' MD, 2909.98' TVD
Start Dir 3.25º/100' : 4741.6' MD, 3986.7'TVD
End Dir : 5387.76' MD, 4509.8' TVD
Total Depth : 7724' MD, 6627.16' TVD
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: NCIU A-21
Water Depth: 101.00
+N/-S +E/-W
Northing Easting Latittude Longitude
0.00 0.00 2586725.65 332001.37 61° 4' 36.3363 N 150° 56' 55.4920 W
SURVEY PROGRAM
Date: 2025-06-05T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
100.00 1416.00 Gyro-GC_Csg (NCIU A-21) 3_Gyro-GC_Csg
1465.34 1600.00 NCIU A-21 MWD+AX+Sag (1) (NCIU A-21)3_MWD+AX+Sag
1600.00 2000.00 NCIU A-21A wp04 (NCIU A-21A wp01) 3_MWD_Interp Azi+Sag
2000.00 7724.00 NCIU A-21A wp04 (NCIU A-21A wp01) 3_MWD+AX+Sag
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: NCIU A-21, True North
Vertical (TVD) Reference:RKB @ 126.63usft
Measured Depth Reference:RKB @ 126.63usft
Calculation Method: Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:Plan: NCIU A-21
Wellbore:NCIU A-21A wp01Design:NCIU A-21A wp04
CASING DETAILS
TVD TVDSS MD Size Name
1554.72 1428.09 1601.00 9-5/8 9-5/8" KOP
6627.16 6500.53 7724.00 4-1/2 4-1/2" x 8-1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 1600.00 38.11 18.78 1553.94 193.36 133.88 0.00 0.00 11.47 KOP: 12.3º/100' : 1600' MD, 1553.94'TVD : 150° LT TF
2 1617.00 36.31 17.01 1567.48 203.14 137.04 12.30 -150.00 14.92 End Dir : 1617' MD, 1567.48' TVD
3 1717.00 36.31 17.01 1648.05 259.77 154.36 0.00 0.00 35.64 Start Dir 4º/100' : 1717' MD, 1648.05'TVD
4 2741.60 28.00 296.00 2552.07 673.10 21.24 4.00 -135.01 392.85
5 3191.60 46.00 296.00 2909.98 791.33 -221.17 4.00 0.00 657.14 End Dir : 3191.6' MD, 2909.98' TVD
6 4741.60 46.00 296.00 3986.70 1280.11 -1223.31 0.00 0.00 1749.76 Start Dir 3.25º/100' : 4741.6' MD, 3986.7'TVD
7 5387.76 25.00 296.00 4509.80 1443.67 -1558.67 3.25 180.00 2115.41 End Dir : 5387.76' MD, 4509.8' TVD
8 7724.00 25.00 296.00 6627.16 1876.50 -2446.09 0.00 0.00 3082.95 Total Depth : 7724' MD, 6627.16' TVD
-200020040060080010001200140016001800200022002400South(-)/North(+) (400 usft/in)-3000 -2800 -2600 -2400 -2200 -2000 -1800 -1600 -1400 -1200 -1000 -800 -600 -400 -200 0 200 400 600West(-)/East(+) (400 usft/in)2505007 50
1 0 0 0125015001750200022502500NCIU A-219-5/8" KOP4-1/2" x 8-1/2"2505007 50
1 0 0 0125015001750200022502500
27503000325035003750400042504500475050005250550057506000625065006627NCIU A-21A wp04KOP: 12.3º/100' : 1600' MD, 1553.94'TVD : 150° LT TFEnd Dir : 1617' MD, 1567.48' TVDStart Dir 4º/100' : 1717' MD, 1648.05'TVDEnd Dir : 3191.6' MD, 2909.98' TVDStart Dir 3.25º/100' : 4741.6' MD, 3986.7'TVDEnd Dir : 5387.76' MD, 4509.8' TVDTotal Depth : 7724' MD, 6627.16' TVDCASING DETAILSTVDTVDSS MDSize Name1554.72 1428.09 1601.00 9-5/8 9-5/8" KOP6627.16 6500.53 7724.00 4-1/2 4-1/2" x 8-1/2"Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-21Wellbore: NCIU A-21A wp01Plan: NCIU A-21A wp04WELL DETAILS: Plan: NCIU A-21Water Depth: 101.00+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.002586725.65 332001.37 61° 4' 36.3363 N 150° 56' 55.4920 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-21, True NorthVertical (TVD) Reference: RKB @ 126.63usftMeasured Depth Reference:RKB @ 126.63usftCalculation Method:Minimum Curvature
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Revised 7/2022
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(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
225-075
NORTH COOK INLET
NCIU A-21A
TERTIARY GAS
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-21AInitial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVWell bore segAnnular DisposalPTD#:2250750Field & Pool:NORTH COOK INLET, TERTIARY GAS - 564570NA1Permit fee attachedYesADL017589 and ADL0378312Lease number appropriateYes3Unique well name and numberYesNORTH COOK INLET, TERTIARY GAS - 564570 - governed by CO 68A4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)YesThis is a redrill from sidetrack just above the surface casing shoe.18Conductor string providedYesThis is a redrill from sidetrack just above the surface casing shoe.19Surface casing protects all known USDWsYesThis is a redrill from sidetrack just above the surface casing shoe.20CMT vol adequate to circulate on conductor & surf csgYesThis is a redrill from sidetrack just above the surface casing shoe.21CMT vol adequate to tie-in long string to surf csgYesFully cement open hole across all annuli.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesSpartan 151 has adequate tankage.24Adequate tankage or reserve pitYes25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows no close approaches with HSE risk26Adequate wellbore separation proposedNA27If diverter required, does it meet regulationsYesAll fluids planned overbalance to pore pressure.28Drilling fluid program schematic & equip list adequateYes3 ram, 1 annular, 1 flow cross rated to 5000 psi29BOPEs, do they meet regulationYes5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNoNot probable but monitoring will be in place.33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated35Permit can be issued w/o hydrogen sulfide measuresYesPotential for shallow gas after kickoff. Max pore pressure anticipated to be 9.8 ppg EMW near TD.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate21-Jul-25ApprMGRDate21-Jul-25ApprADDDate21-Jul-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 7/22/2025
