Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout224-086Alaska 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
November 24, 2025
Dan Marlow
CIO Operations Manager
Hilcorp Alaska LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Docket Number OTH-25-011
Notice of Violation – Compliance with Sundry Number 324-528
Closeout
North Cook Inlet Unit Well A-21 (PTD 224-086)
Dear Mr. Marlow:
The Alaska Oil and Gas Conservation Commission (AOGCC) reviewed Hilcorp Alaska, LLC
(Hilcorp)’s March 13, 2025, explanation regarding the failure to pressure test to approved values
specified in the Sundry 324-528. Hilcorp has satisfied the request made in our March 4, 2025,
notice of violation. The AOGCC does not intend to pursue any further enforcement action
regarding this violation.
Sincerely,
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
cc: Bryan McLellan
Phoebe Brooks
Gregory C Wilson
Digitally signed by Gregory C
Wilson
Date: 2025.11.24 08:31:28 -09'00'
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2025.11.24 08:34:13
-09'00'
03/13/2025
Commissioners – Jesse Chmielowski and Greg Wilson
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, Alaska 99501
Subject: Response to Docket Number: OTH-25-011, Notice of Violation, Compliance with Sundry Number
324-528, NCIU A-21 (PTD 224-086).
Dear Commissioner Chmielowski and Commissioner Wilson,
Hilcorp has reviewed the circumstances around the failures to pressure test to approved values specified in the Sundry
for recent operations on NCIU A-21. Please see the details below regarding how Hilcorp intends to prevent recurrence
of this event.
Causes of the incident:
x Inadequate review of the sundry procedure resulting in pressure testing to values below what is specified in
the approved sundry.
Contributing factors of the incident:
x Lack of communication between wellsite personnel and the responsible engineer specifically around the topic
of pressure control equipment pressure testing targets.
Actions to prevent recurrence:
x Hilcorp has reviewed PCE pressure test requirements and the importance of following the sundry procedure
with our Operations Engineers and Wellsite Supervisors.
o The NCIU A-21 failure was reviewed in our monthly HAK/HNS Operations Engineer and
Operations Manager meeting on 3/6 including reviewing:
20 AAC 25.507 requirement for approval for substantive change to approved programs.
20 AAC 25.287 requirement for wireline PCE to be tested before wellbore entry to the
maximum potential wellhead pressure to which that equipment may be subjected.
o A bulletin with a summary of the event and details of 20 AAC 25.507, 20 AAC 25.287 and 20 AAC
25.526 requirements will be distributed to Operations Engineers and Wellsite Supervisors at all HAK
and HNS fields.
Hilcorp Alaska, LLC
Dan Marlowe, CIO Operations Manager
3800 Centerpoint Dr, Suite 1400
Anchorage, Alaska 99503
x As part of Hilcorp’s 2024 AOGCC regulatory gap assessment, training completion percentages for existing
computer-based training were found to be poor (15-20% completion for office personnel). As of February
2025, training assignments for Hilcorp Operations Engineers and Wellsite Supervisors have been
corrected/verified and communicated as a requirement for completion every 24 months.
o One of the existing CBT modules focusing on “Sundry Requirements” includes a dedicated slide
emphasizing the requirements of 20 AAC 25.507 for changes to approve programs as shown in
Figure 1 below
Figure 1: Hilcorp Sundry Requirements Training - Changes to Approve Program
o Additionally, the Sundry Requirements CBT module summarizes wireline well control requirements
per 20 AAC 25.287 including requirement to pressure test wireline PCE to the maximum expected
pressure it may be subjected as shown in Figure 2 below.
Figure 2: Hilcorp Sundry Requirements Training - Wireline PCE Testing Requirements
o Finally, the Sundry Requirements CBT module reinforces the importance of good conduct of
operations including AOGCC requirements per 20 AAC 25.526 in Figure 3 below.
Figure 3: Hilcorp Sundry Requirements Training - Conduct of Operations
If you have any questions, please contact me at (907)283-1329.
Sincerely,
Dan Marlowe
CIO Operations Manger
CC Bryan McLellan
Mel Rixse
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.03.13 05:53:34 -
08'00'
Dan Marlowe
(1267)
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:6 Township:11N Range:9W Meridian:Seward
Drilling Rig:Hilcorp 151 Rig Elevation:126.6 ft Total Depth:11394 ft MD Lease No.:ADL0017589
Operator Rep:Suspend:P&A:X
Conductor:30"O.D. Shoe@ 384 Feet Csg Cut@ Feet
Surface:9-5/8"O.D. Shoe@ 5909 Feet Csg Cut@ Feet
Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet
Production:4-1/2"O.D. Shoe@ 11391 Feet Csg Cut@ Feet
Liner:O.D. Shoe@ Feet Csg Cut@ Feet
Tubing:4-1/2"O.D. Tail@ 5766 Feet Tbg Cut@ 5766 Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Fullbore Fill 6266 ft 5300 ft 8.6 ppg Drillpipe tag
Initial 15 min 30 min 45 min Result
Tubing
IA 3274 3203 3170
OA 0 0 0
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Remarks:
Attachments:
The tubing had been pulled afrom the polished bore recepticle. MIT was a casing test with 5.6 bbls pumped and 5.5 bbls
returned. Tag was good and solid with 15K lbs down.
August 2, 2025
Kam StJohn
Well Bore Plug & Abandonment
NCIU A-21
Hilcorp Alaska LLC
PTD 2240860; Sundry 325-452
Test Chart
Test Data:
P
Casing Removal:
Sloan Sunderland
Casing/Tubing Data (depths are MD):
Plugging Data (depths are MD):
rev. 3-24-2022 2025-0802_Plug_Verification_NCIU_A-21_ksj
Plug Verification – NCIU A-21 (PTD 2240860)
Photo by AOGCC Inspector K. StJohn
8/2/2025
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
March 4, 2025
CERTIFIED MAIL –
RETURN RECEIPT REQUESTED
7018 0680 0002 2052 9525
Mr. Dan Marlow
Hilcorp Alaska, LLC
P.O. Box 244027
Anchorage, AK 99524-4027
Re: Docket Number: OTH-25-011
Notice of Violation
Compliance with Sundry Number 324-528
NCIU A-21 (PTD 224-086)
Dear Mr. Marlow:
The Alaska Oil and Gas Conservation Commission (AOGCC) hereby notifies Hilcorp Alaska,
LLC (Hilcorp) of a Notice of Violation to 20 AAC 25.507, Change of an approved program, and
to 20 AAC 25.526, Conduct of operations.
On September 19, 2024, the AOGCC conditionally approved Sundry #324-528, authorizing
Hilcorp to perform Coiled Tubing, E-line and nitrogen workover operations to perforate the newly
drilled well North Cook Inlet Unit (NCIU) A-21. The operations conducted under this Sundry
began on September 28, 2024, and were completed on January 21, 2025, according to the Well
Completion or Recompletion Report (Form 10-407), received by AOGCC on February 11, 2025.
On February 10, 2025, Hilcorp self-reported to the AOGCC that the following tests were
performed at a pressure that was lower than what is specified in the approved sundry:
- Step 2 of the E-line Perforation procedure specified: “PT [pressure test] lubricator to 250
psi low /3000 psi high”.
o The Weekly Operations Report submitted with the Form 10-407 (and submitted
with Hilcorp’s February 10, 2025, notification) indicates that on October 1 and
October 3, 2024, the E-line lubricator was pressure tested to only 1500 psi.
- Step 1 of the Contingency plug/patch procedure specified: “RU [rig up] nitrogen to tubing
and PT lines to 3000 psi (or higher if needed)”.
Docket Number: OTH-25-011
Notice of Violation
March 4, 2025
Page 2 of 2
o The Weekly Operations Report submitted with the Form 10-407 (and submitted
with Hilcorp’s February 10, 2025, notification) indicates that on January 12, 2025,
the nitrogen lines were tested to only 2500 psi.
AOGCC’s investigation indicates Hilcorp failed to obtain approval to change the pressure test
values specified in the approved Sundry for pressure testing the E-line lubricator and the nitrogen
treating lines. The test pressures executed in the field of 1500 psi for E-line lubricator and 2500
psi for the nitrogen lines were both below the maximum potential surface pressure (MPSP) of 2764
psi as specified in the approved sundry.
Failure to follow the procedures in an approved Sundry is a violation of 20 AAC 25.507. Failure
to test equipment to a pressure above the MPSP creates a potentially dangerous situation and is a
violation of 20 AAC 25.526.
Within 14 days after receipt of this letter (or the next business day if the due date falls on a
weekend or holiday), Hilcorp is required to provide a detailed written explanation that describes
how Hilcorp intends to prevent recurrence of this violation.
The AOGCC reserves the right to pursue additional enforcement action in connection with this
Notice of Violation. Questions regarding this letter should be directed to Bryan McLellan at
(907) 793-1226 (bryan.mclellan@alaska.gov).
Sincerely,
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
cc: Phoebe Brooks
James Regg
Bryan McLellan
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2025.03.04
14:20:19 -09'00'
Gregory C. Wilson
Digitally signed by Gregory C.
Wilson
Date: 2025.03.04 15:33:28 -09'00'
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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: 08/26/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250826
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF
T40803
BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist
T40804
BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf
T40804
BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf
T40804
BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf
T40805
BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf
T40805
BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch
T40806
KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf
T40807
MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey
T40808
NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf
T40809
ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey
T40810
PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG
T40811
PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG
T40812
PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT
T40813
PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG
T40814
PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG
T40815
PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG
T40816
PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf
T40817
SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf
T40818
WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer
T40819
Please include current contact information if different from above.
T40809NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.08.27 08:12:23 -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: 08/15/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250815
Well API # PTD # Log Date Log
Company Log Type AOGCC
E-Set#
NCIU A-21 (REVISED) 50883201990000 224086 2/18/2025 AK E-LINE PERF/CIBP/TOCTAG
Revision Explanation: This is a revision to NCIU A-21 Perf 2/18/25 from transmittal T#20250302
AOGCC E-Set# T40169. This revision includes additional services being CIBP and TOC Tag.
Please include current contact information if different from above.
T40785
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.08.15 13:41:29 -08'00'
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):
11,394 10,163
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: Sean Mclaughlin
Contact Email:sean.mclaughlin@hilcorp.com
Contact Phone:907-223-6784
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:
North Cook Inlet Tertiary System Gas Same
6,925 6450'3731'1,223psi 6450' top plug
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):
Drilling Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
224-086
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-00-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21
Length Size
Proposed Pools:
L-80
TVD Burst
5,766
8,430psi
MD
1,630psi
6,870psi
384'
3,501'
384'
5,909'
30"
9-5/8"
384'
5,909'
6373-6424
5,655'
3706-3729
6,923'4-1/2"11,391'
7/31/2025
4-1/2"
LTP & Baker TE-5 5,758 (MD) 3,437 (TVD) & 446 (MD) 446 (TVD)
Perforation Depth MD (ft):
m
n
P
s
2
6
5
6
t c
N
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 Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.07.31 10:33:01 -
08'00'
Sean
McLaughlin
(4311)
325-452
By Grace Christianson at 10:41 am, Jul 31, 2025
MGR31JUL2025 A.Dewhurst 31JUL25
* BOPE pressure test to be performed to 3000 psi. Annular to 2500 psi. 48 hour notice.
* Variance to 20 AAC 25.112(c)(1)(C) approved. Fill permeability demonstrated to be extremely limited at
3000 psi injectivity test.
* AOGCC to witness drill pipe tag and pressure test as described. 48 hour notice.10-407
JLC 8/1/2025
Gregory C. Wilson
Digitally signed by Gregory C.
Wilson
Date: 2025.08.01 12:12:40 -08'00'08/01/25
RBDMS JSB 080525
Well Prognosis
Well: NCIU A-21
Date: 7/31/25
Well Name:NCIU A-21 API Number:50-883-20199-00-00
Current Status:Picking Up Drill Pipe
Estimated Start Date:7/31/25 Rig:Spartan 151
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-086
First Call Engineer:Sean Mclaughlin 907-223-6784
Second Call Engineer
Sundry Number:325-410
Attachments:
1.Current Schematic
2.Proposed Schematic
3.BOPE Schematic (edited)
Change to Approved Program Request:
Hilcorp is requesting a change to the approved sundry 325-410 (plug for redrill).
Current Status
Rig 151 has pressured up on the 4-1/2” tubing to 3000 psi and is unable to achieve injectivity into the
open perforations. The BOPE test is currently completed and the rig is picking up drill pipe.
Procedure:
1. Make up landing joint, pump through tubing to a maximum of 4000 psi in attempt to gain
injectivity into the perforations.
a. The 4-1/2” 12.6# L-80 tubing is rated to 8,430 psi burst.
b. If injection is achieved, then revert to the original Sundry (325-410).
2. Pull 4-1/2” tubing from PBR as programed.
3. Make up a 500’ 2-7/8” clean out BHA. And RIH with 5” DP.
4. Clean out 500’ into the 4-1/2” liner. If washing through a sand bridge be prepared for lost
circulation and stuck pipe occurring below the bridge.
5. Lay in 40 bbls of 15.3# cement from 500’ inside the 4-1/2” liner (6266’ bottom of cement plug)
a. 7.6 bbls – 500’ of 4-1/2” liner
b. 32.4 bbls – above 4-1/2” liner in 9-5/8” casing (~442’)
c. TOC expected at 5324’
6. LD 2-7/8” BHA
7. WOC –Give AOGCC 48 hr notice for tag and PT witness opportunity.
8. Tag TOC with minimum of 15klbs. Pressure Test cement plug and casing to 3000 psi.
9. Continue operations on APD (225-075)
Variance Request
20 AAC 25.112(c)(1)(C) -however, the commission will approve plugging from the top of fill or the top
of junk instead of from the plugged-back total depth, if the commission determines that the objectives of this
subsection will be met’
Justification:
- Hard pack fill is expected in the 4-1/2” tubing
- A fill cleanout past the perforations would unnecessarily expose the operation to loss circulation,
stuck pipe, and well control risk
_____________________________________________________________________________________
Updated By: CJD 7/31/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
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 5,909’
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”5,736’11,391’
TUBING DETAIL
4-1/2"Prod Tieback 12.6 L-80 IBT-M 3.958”Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’446'6.620"Baker TE S-5 SSSV
2 1008’1,006'ES Cementer
3 5,711’3,417'3.813"X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’3,437'3.958"Liner hanger / LTP Assembly
5 5,766’3,440'3.958"Seal Stem
6 6,450’3,741’-CIBP (04/01/25)
7 7,050’4,001’-CIBP (03/30/25)
8 7,460’4,173’-CIBP (03/29/25)
9 8,630’4,700’-CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’5,090’-CIBP (01/17/25)
11 9,380’5,186’-CIBP (01/16/25)
12 9,775’5,502’-CIBP (01/13/25)
13 10,130’5,810’-CIBP (01/08/25)
14 10,570’6,197’-CIBP (10/29/24)
15 10,670’6,286’-CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’6,383’3,706’3,711’10’04/04/25 Open
Aa 6,414’6,424’3,725’3,729’10’04/01/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’2,012'3.833"GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’3,395'3.833"GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2”Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384'GCBD with RA tag in collar
10,387'GCBD with RA tag in collar
Updated By: CJD 7/31/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’6,467’3,744’3,749’10’03/31/25 Isolated (04/01/25)
B 6,561’6,571’3,791’3,796’10’03/31/25 Isolated (04/01/25)
CI 1 7,063’7,073’4,006’4,010’10’03/29/25 Isolated (03/30/25)
CI 2 7,274’7,284’4,095’4,100’10’03/29/25 Isolated (03/30/25)
CI 3 7,474’7,484’4,179’4,183’10’02/19/25 Isolated (03/29/25)
CI 8 8,226’8,234’4,508’4,511’8’02/19/25 Isolated (03/29/25)
CI 12a 8,564’8,572’4,666’4,670’8’02/18/25 Isolated (03/29/25)
Bel Aa 8,634’8,662’4,702’4,717’28’01/21/25 Isolated (02/16/25)
Bel Ba 8,833’8,847’4,814’4,822’14’01/20/25 Isolated (02/16/25)
Bel Bb 8,856’8,872’4,828’4,837’16’01/20/25 Isolated (02/16/25)
Bel Bd 8,954’8,965’4,889’4,896’11’01/19/25 Isolated (02/16/25)
Del Be 9,000’9,004’4,919’4,922’4’01/19/25 Isolated (02/16/25)
Bel Bf 9,022’9,028’4,934’4,938’6’01/19/25 Isolated (02/16/25)
Bel Ca 9,064’9,074’4,962’4,968’10’01/18/25 Isolated (02/16/25)
Bel Cb 9,084’9,094’4,975’4,982’10’01/18/25 Isolated (02/16/25)
Bel Cc 9,103’9,113’4,988’4,995’10’01/18/25 Isolated (02/16/25)
Bel Da 9,200’9,210’5,055’5,062’10’01/18/25 Isolated (02/16/25)
Bel Db 9,218’9,224’5,068’5,072’6’01/18/25 Isolated (02/16/25)
Bel Dc 9,233’9,238’5,078’5,082’5’01/18/25 Isolated (02/16/25)
Bel Dd 9,263’9,283’5,099’5,144’20’01/15/25 Isolated (01/17/25)
Bel De 9,319’9,339’5,140’5,155’20’01/15/25 Isolated (01/17/25)
Bel Df 9,350’9,367’5,163’5,176’17’01/14/25 Isolated (01/17/25)
Bel Ea 9,390’9,400’5,193’5,201’10’01/14/25 Isolated (01/16/25)
Bel Eb 9,432’9,452’5,225’5,240’20’01/13/25 Isolated (01/16/25)
Bel Ha 9,795’9,811’5,519’5,533’16’01/11/25 Isolated (01/13/25)
Bel Jc 10,173’10,179’5,848’5,853’6’11/10/24 Isolated (01/08/25)
Bel Ma 10,386’10,396’6,035’6,044’10’11/9/24 Isolated (01/08/25)
Bel Mb 10,408’10,414’6,054’6,060’6’11/9/24 Isolated (01/08/25)
Bel Mc 10,424’10,444’6,068’6,086’20’10/31/24 Isolated (01/08/25)
Bel N 10,460’10,464’6,100’6,104’4’10/29/24 Isolated (01/08/25)
Bel Oa 10,502’10,508’6,137’6,142’6’10/29/24 Isolated (01/08/25)
Bel Ob 10,516’10,530’6,147’6,162’14’10/29/24 Isolated (01/08/25)
Bel P 10,578’10,584’6,204’6,210’6’10/28/24 Isolated (10/29/24)
Bel Pb 10,602’10,608’6,226’6,231’6’10/28/24 Isolated (10/29/24)
Bel Pc 10,629’10,643’6,249’6,262’14’10/17/24 Isolated (10/29/24)
Bel Qa 10,678’10,684’6,293’6,298’6’10/17/24 Isolated (10/27/24)
Bel Qb 10,742’10,756’6,349’6,362’14’10/17/24 Isolated (10/27/24)
Bel Qc 10,777’10,783’6,380’6,386’6’10/17/24 Isolated (10/27/24)
Bel Ra 10,825’10,835’6,423’6,432’10’10/17/24 Isolated (10/27/24)
Bel Rb 10,844’10,850’6,440’6,445’6’10/17/24 Isolated (10/27/24)
Bel Rc 10,884’10,890’6,475’6,480’6’10/17/24 Isolated (10/27/24)
Bel Rd 10,918’10,928’6,505’6,514’10’10/17/24 Isolated (10/27/24)
Bel Sa 10,946’10,956’6,530’6,539’10’10/16/24 Isolated (10/27/24)
Bel S 11,056’11,062’6,627’6,632’6’10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’6,728’10’10/16/24 Isolated (10/27/24)
_____________________________________________________________________________________
Updated By: CJD 7/31/25
Proposed SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
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 5,909’
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”5,736’11,391’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 1008’1,006'ES Cementer
2 1,600’1,554’Whipstock
3 5,324’3,270’Cement Plug TOC 5324’ Bottom 6266’ MD
4 5,758’3,437'3.958"Liner hanger / LTP Assembly
5 5,766’3,440'3.958"Seal Stem
6 6,450’3,741’-CIBP (04/01/25)
7 7,050’4,001’-CIBP (03/30/25)
8 7,460’4,173’-CIBP (03/29/25)
9 8,630’4,700’-CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’5,090’-CIBP (01/17/25)
11 9,380’5,186’-CIBP (01/16/25)
12 9,775’5,502’-CIBP (01/13/25)
13 10,130’5,810’-CIBP (01/08/25)
14 10,570’6,197’-CIBP (10/29/24)
15 10,670’6,286’-CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’6,383’3,706’3,711’10’04/04/25 Plug
Aa 6,414’6,424’3,725’3,729’10’04/01/25 Plug
Isolated Perforation Details on Page 2
FISH DETAILS
10,163’12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2”Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384'GCBD with RA tag in collar
10,387'GCBD with RA tag in collar
Updated By: CJD 7/31/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’6,467’3,744’3,749’10’03/31/25 Isolated (04/01/25)
B 6,561’6,571’3,791’3,796’10’03/31/25 Isolated (04/01/25)
CI 1 7,063’7,073’4,006’4,010’10’03/29/25 Isolated (03/30/25)
CI 2 7,274’7,284’4,095’4,100’10’03/29/25 Isolated (03/30/25)
CI 3 7,474’7,484’4,179’4,183’10’02/19/25 Isolated (03/29/25)
CI 8 8,226’8,234’4,508’4,511’8’02/19/25 Isolated (03/29/25)
CI 12a 8,564’8,572’4,666’4,670’8’02/18/25 Isolated (03/29/25)
Bel Aa 8,634’8,662’4,702’4,717’28’01/21/25 Isolated (02/16/25)
Bel Ba 8,833’8,847’4,814’4,822’14’01/20/25 Isolated (02/16/25)
Bel Bb 8,856’8,872’4,828’4,837’16’01/20/25 Isolated (02/16/25)
Bel Bd 8,954’8,965’4,889’4,896’11’01/19/25 Isolated (02/16/25)
Del Be 9,000’9,004’4,919’4,922’4’01/19/25 Isolated (02/16/25)
Bel Bf 9,022’9,028’4,934’4,938’6’01/19/25 Isolated (02/16/25)
Bel Ca 9,064’9,074’4,962’4,968’10’01/18/25 Isolated (02/16/25)
Bel Cb 9,084’9,094’4,975’4,982’10’01/18/25 Isolated (02/16/25)
Bel Cc 9,103’9,113’4,988’4,995’10’01/18/25 Isolated (02/16/25)
Bel Da 9,200’9,210’5,055’5,062’10’01/18/25 Isolated (02/16/25)
Bel Db 9,218’9,224’5,068’5,072’6’01/18/25 Isolated (02/16/25)
Bel Dc 9,233’9,238’5,078’5,082’5’01/18/25 Isolated (02/16/25)
Bel Dd 9,263’9,283’5,099’5,144’20’01/15/25 Isolated (01/17/25)
Bel De 9,319’9,339’5,140’5,155’20’01/15/25 Isolated (01/17/25)
Bel Df 9,350’9,367’5,163’5,176’17’01/14/25 Isolated (01/17/25)
Bel Ea 9,390’9,400’5,193’5,201’10’01/14/25 Isolated (01/16/25)
Bel Eb 9,432’9,452’5,225’5,240’20’01/13/25 Isolated (01/16/25)
Bel Ha 9,795’9,811’5,519’5,533’16’01/11/25 Isolated (01/13/25)
Bel Jc 10,173’10,179’5,848’5,853’6’11/10/24 Isolated (01/08/25)
Bel Ma 10,386’10,396’6,035’6,044’10’11/9/24 Isolated (01/08/25)
Bel Mb 10,408’10,414’6,054’6,060’6’11/9/24 Isolated (01/08/25)
Bel Mc 10,424’10,444’6,068’6,086’20’10/31/24 Isolated (01/08/25)
Bel N 10,460’10,464’6,100’6,104’4’10/29/24 Isolated (01/08/25)
Bel Oa 10,502’10,508’6,137’6,142’6’10/29/24 Isolated (01/08/25)
Bel Ob 10,516’10,530’6,147’6,162’14’10/29/24 Isolated (01/08/25)
Bel P 10,578’10,584’6,204’6,210’6’10/28/24 Isolated (10/29/24)
Bel Pb 10,602’10,608’6,226’6,231’6’10/28/24 Isolated (10/29/24)
Bel Pc 10,629’10,643’6,249’6,262’14’10/17/24 Isolated (10/29/24)
Bel Qa 10,678’10,684’6,293’6,298’6’10/17/24 Isolated (10/27/24)
Bel Qb 10,742’10,756’6,349’6,362’14’10/17/24 Isolated (10/27/24)
Bel Qc 10,777’10,783’6,380’6,386’6’10/17/24 Isolated (10/27/24)
Bel Ra 10,825’10,835’6,423’6,432’10’10/17/24 Isolated (10/27/24)
Bel Rb 10,844’10,850’6,440’6,445’6’10/17/24 Isolated (10/27/24)
Bel Rc 10,884’10,890’6,475’6,480’6’10/17/24 Isolated (10/27/24)
Bel Rd 10,918’10,928’6,505’6,514’10’10/17/24 Isolated (10/27/24)
Bel Sa 10,946’10,956’6,530’6,539’10’10/16/24 Isolated (10/27/24)
Bel S 11,056’11,062’6,627’6,632’6’10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’6,728’10’10/16/24 Isolated (10/27/24)
Well Prognosis
Well: NCIU A-21
Date: 7/31/25
- A solid sand plug in the tubing is a suitable base to place cement on top of.
- Additional cement volume and increased plug length (~900’ planned) would ensure a long lateral
barrier across all casing strings.
BOPE Schematic
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-21
JBR 09/09/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
CMV# 3 had to be serviced and flange leak under the Annular, tightened up. Both passed re-tests.
Test Results
TEST DATA
Rig Rep:B. Herbert/ D. BoydOperator:Hilcorp Alaska, LLC Operator Rep:S. Sunderland/ S. Dambacke
Rig Owner/Rig No.:Hilcorp 151 PTD#:2240860 DATE:7/30/2025
Type Operation:WRKOV Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopAGE250803153432
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 14
MASP:
1223
Sundry No:
325-410
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
13 FPNo. Valves
1 PManual Chokes
2 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8 FP
#1 Rams 1 2 7/8x5 1/2 P
#2 Rams 1 Blinds P
#3 Rams 1 2 7/8x5 1/2 P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8 P
HCR Valves 2 3 1/8 P
Kill Line Valves 3 3 1/8 & 3 1/16 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3025
Pressure After Closure P1600
200 PSI Attained P30
Full Pressure Attained P168
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P16@2150
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P12
#1 Rams P10
#2 Rams P10
#3 Rams P11
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
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):
11,394 10,163
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: Sean Mclaughlin
Contact Email:sean.mclaughlin@hilcorp.com
Contact Phone:907-223-6784
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
7/29/2025
4-1/2"
LTP & Baker TE-5 5,758 (MD) 3,437 (TVD) & 446 (MD) 446 (TVD)
Perforation Depth MD (ft):
6373-6424
5,655'
3706-3729
6,923'4-1/2"11,391'
30"
9-5/8"
384'
5,909'
MD
1,630psi
6,870psi
384'
3,501'
384'
5,909'
Length Size
Proposed Pools:
L-80
TVD Burst
5,766
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
224-086
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-00-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Drilling 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
6,925 6450'3731'1,223psi 6450' top plug
CO 68A
m
n
P
s
2
6
5
6
tc
N
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 3:07 pm, Jul 29, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.07.29 14:27:10 -
08'00'
Sean
McLaughlin
(4311)
325-448
* BOPE test to 3000 psi. Annular to 2500 psi.
10-407
Original A-21A Completion Report
A.Dewhurst 29JUL25MGR30JUL2025*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.07.31 08:54:31 -08'00'07/31/25
RBDMS JSB 073125
Well Prognosis
Well: NCIU A-21
Date: 7/29/25
Well Name:NCIU A-21 API Number:50-883-20199-00-00
Current Status:Rigging Up
Estimated Start Date:7/29/25 Rig:Spartan 151
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-086
First Call Engineer:Sean Mclaughlin 907-223-6784
Second Call Engineer
AFE Number:
Attachments:
1.Current Schematic
2.Proposed Schematic
3.BOPE Schematic (edited)
Change to Approved Program Request:
Hilcorp is requesting a change to the BOPE configuration due to issues rigging up over NCIU A-21. During rig up
of Rig 151 we found that there was interference with the substructure opening and the mud cross. We will
plan to drop the mud cross and rig up the choke and kill lines to the lower 4-1/16” 5M outlet on the 13-5/8”
double gate. There will be no change to standing orders or choke/kill functionality. If approved, this
configuration will apply to the plug for redrill (NCIU A-21) and the sidetrack operations (NCIU A-21A)
_____________________________________________________________________________________
Updated By: JLL 04/29/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
10
13
14
15
12
11
6
7
8
9
1
2
Sterling
Sands
3/4/5
Bel T
Bel Q
Bel S
Bel R
Bel P
Bel N
Bel O
Bel M
Bel J
Bel H
Bel E
Bel D
Bel B
Bel C
Bel D
Bel A
C I
C I
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’ 446' 6.620" Baker TE S-5 SSSV
2 1008’ 1,006' ES Cementer
3 5,711’ 3,417' 3.813" X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’ 3,437' 3.958" Liner hanger / LTP Assembly
5 5,766’ 3,440' 3.958" Seal Stem
6 6,450’ 3,741’ - CIBP (04/01/25)
7 7,050’ 4,001’ - CIBP (03/30/25)
8 7,460’ 4,173’ - CIBP (03/29/25)
9 8,630’ 4,700’ - CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’ 5,090’ - CIBP (01/17/25)
11 9,380’ 5,186’ - CIBP (01/16/25)
12 9,775’ 5,502’ - CIBP (01/13/25)
13 10,130’ 5,810’ - CIBP (01/08/25)
14 10,570’ 6,197’ - CIBP (10/29/24)
15 10,670’ 6,286’ - CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’ 6,383’ 3,706’ 3,711’ 10’ 04/04/25 Open
Aa 6,414’ 6,424’ 3,725’ 3,729’ 10’ 04/01/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’ 2,012' 3.833" GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’ 3,395' 3.833" GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’ 12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
Updated By: JLL 04/29/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’ 6,467’ 3,744’ 3,749’ 10’ 03/31/25 Isolated (04/01/25)
B 6,561’ 6,571’ 3,791’ 3,796’ 10’ 03/31/25 Isolated (04/01/25)
CI 1 7,063’ 7,073’ 4,006’ 4,010’ 10’ 03/29/25 Isolated (03/30/25)
CI 2 7,274’ 7,284’ 4,095’ 4,100’ 10’ 03/29/25 Isolated (03/30/25)
CI 3 7,474’ 7,484’ 4,179’ 4,183’ 10’ 02/19/25 Isolated (03/29/25)
CI 8 8,226’ 8,234’ 4,508’ 4,511’ 8’ 02/19/25 Isolated (03/29/25)
CI 12a 8,564’ 8,572’ 4,666’ 4,670’ 8’ 02/18/25 Isolated (03/29/25)
Bel Aa 8,634’ 8,662’ 4,702’ 4,717’ 28’ 01/21/25 Isolated (02/16/25)
Bel Ba 8,833’ 8,847’ 4,814’ 4,822’ 14’ 01/20/25 Isolated (02/16/25)
Bel Bb 8,856’ 8,872’ 4,828’ 4,837’ 16’ 01/20/25 Isolated (02/16/25)
Bel Bd 8,954’ 8,965’ 4,889’ 4,896’ 11’ 01/19/25 Isolated (02/16/25)
Del Be 9,000’ 9,004’ 4,919’ 4,922’ 4’ 01/19/25 Isolated (02/16/25)
Bel Bf 9,022’ 9,028’ 4,934’ 4,938’ 6’ 01/19/25 Isolated (02/16/25)
Bel Ca 9,064’ 9,074’ 4,962’ 4,968’ 10’ 01/18/25 Isolated (02/16/25)
Bel Cb 9,084’ 9,094’ 4,975’ 4,982’ 10’ 01/18/25 Isolated (02/16/25)
Bel Cc 9,103’ 9,113’ 4,988’ 4,995’ 10’ 01/18/25 Isolated (02/16/25)
Bel Da 9,200’ 9,210’ 5,055’ 5,062’ 10’ 01/18/25 Isolated (02/16/25)
Bel Db 9,218’ 9,224’ 5,068’ 5,072’ 6’ 01/18/25 Isolated (02/16/25)
Bel Dc 9,233’ 9,238’ 5,078’ 5,082’ 5’ 01/18/25 Isolated (02/16/25)
Bel Dd 9,263’ 9,283’ 5,099’ 5,144’ 20’ 01/15/25 Isolated (01/17/25)
Bel De 9,319’ 9,339’ 5,140’ 5,155’ 20’ 01/15/25 Isolated (01/17/25)
Bel Df 9,350’ 9,367’ 5,163’ 5,176’ 17’ 01/14/25 Isolated (01/17/25)
Bel Ea 9,390’ 9,400’ 5,193’ 5,201’ 10’ 01/14/25 Isolated (01/16/25)
Bel Eb 9,432’ 9,452’ 5,225’ 5,240’ 20’ 01/13/25 Isolated (01/16/25)
Bel Ha 9,795’ 9,811’ 5,519’ 5,533’ 16’ 01/11/25 Isolated (01/13/25)
Bel Jc 10,173’ 10,179’ 5,848’ 5,853’ 6’ 11/10/24 Isolated (01/08/25)
Bel Ma 10,386’ 10,396’ 6,035’ 6,044’ 10’ 11/9/24 Isolated (01/08/25)
Bel Mb 10,408’ 10,414’ 6,054’ 6,060’ 6’ 11/9/24 Isolated (01/08/25)
Bel Mc 10,424’ 10,444’ 6,068’ 6,086’ 20’ 10/31/24 Isolated (01/08/25)
Bel N 10,460’ 10,464’ 6,100’ 6,104’ 4’ 10/29/24 Isolated (01/08/25)
Bel Oa 10,502’ 10,508’ 6,137’ 6,142’ 6’ 10/29/24 Isolated (01/08/25)
Bel Ob 10,516’ 10,530’ 6,147’ 6,162’ 14’ 10/29/24 Isolated (01/08/25)
Bel P 10,578’ 10,584’ 6,204’ 6,210’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pb 10,602’ 10,608’ 6,226’ 6,231’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pc 10,629’ 10,643’ 6,249’ 6,262’ 14’ 10/17/24 Isolated (10/29/24)
Bel Qa 10,678’ 10,684’ 6,293’ 6,298’ 6’ 10/17/24 Isolated (10/27/24)
Bel Qb 10,742’ 10,756’ 6,349’ 6,362’ 14’ 10/17/24 Isolated (10/27/24)
Bel Qc 10,777’ 10,783’ 6,380’ 6,386’ 6’ 10/17/24 Isolated (10/27/24)
Bel Ra 10,825’ 10,835’ 6,423’ 6,432’ 10’ 10/17/24 Isolated (10/27/24)
Bel Rb 10,844’ 10,850’ 6,440’ 6,445’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rc 10,884’ 10,890’ 6,475’ 6,480’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rd 10,918’ 10,928’ 6,505’ 6,514’ 10’ 10/17/24 Isolated (10/27/24)
Bel Sa 10,946’ 10,956’ 6,530’ 6,539’ 10’ 10/16/24 Isolated (10/27/24)
Bel S 11,056’ 11,062’ 6,627’ 6,632’ 6’ 10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’ 6,728’ 10’ 10/16/24 Isolated (10/27/24)
_____________________________________________________________________________________
Updated By: CJD 7/9/25
Proposed SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
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 5,909’
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”5,736’11,391’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 1008’1,006'ES Cementer
2 1,600’1,554’Whipstock
3 5,600’3,372'Cement Retainer w 400’ cmt on top
4 5,758’3,437'3.958"Liner hanger / LTP Assembly
5 5,766’3,440'3.958"Seal Stem
6 6,450’3,741’-CIBP (04/01/25)
7 7,050’4,001’-CIBP (03/30/25)
8 7,460’4,173’-CIBP (03/29/25)
9 8,630’4,700’-CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’5,090’-CIBP (01/17/25)
11 9,380’5,186’-CIBP (01/16/25)
12 9,775’5,502’-CIBP (01/13/25)
13 10,130’5,810’-CIBP (01/08/25)
14 10,570’6,197’-CIBP (10/29/24)
15 10,670’6,286’-CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’6,383’3,706’3,711’10’04/04/25 Plug
Aa 6,414’6,424’3,725’3,729’10’04/01/25 Plug
Isolated Perforation Details on Page 2
FISH DETAILS
10,163’12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2”Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384'GCBD with RA tag in collar
10,387'GCBD with RA tag in collar
Updated By: JLL 7/9/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’6,467’3,744’3,749’10’03/31/25 Isolated (04/01/25)
B 6,561’6,571’3,791’3,796’10’03/31/25 Isolated (04/01/25)
CI 1 7,063’7,073’4,006’4,010’10’03/29/25 Isolated (03/30/25)
CI 2 7,274’7,284’4,095’4,100’10’03/29/25 Isolated (03/30/25)
CI 3 7,474’7,484’4,179’4,183’10’02/19/25 Isolated (03/29/25)
CI 8 8,226’8,234’4,508’4,511’8’02/19/25 Isolated (03/29/25)
CI 12a 8,564’8,572’4,666’4,670’8’02/18/25 Isolated (03/29/25)
Bel Aa 8,634’8,662’4,702’4,717’28’01/21/25 Isolated (02/16/25)
Bel Ba 8,833’8,847’4,814’4,822’14’01/20/25 Isolated (02/16/25)
Bel Bb 8,856’8,872’4,828’4,837’16’01/20/25 Isolated (02/16/25)
Bel Bd 8,954’8,965’4,889’4,896’11’01/19/25 Isolated (02/16/25)
Del Be 9,000’9,004’4,919’4,922’4’01/19/25 Isolated (02/16/25)
Bel Bf 9,022’9,028’4,934’4,938’6’01/19/25 Isolated (02/16/25)
Bel Ca 9,064’9,074’4,962’4,968’10’01/18/25 Isolated (02/16/25)
Bel Cb 9,084’9,094’4,975’4,982’10’01/18/25 Isolated (02/16/25)
Bel Cc 9,103’9,113’4,988’4,995’10’01/18/25 Isolated (02/16/25)
Bel Da 9,200’9,210’5,055’5,062’10’01/18/25 Isolated (02/16/25)
Bel Db 9,218’9,224’5,068’5,072’6’01/18/25 Isolated (02/16/25)
Bel Dc 9,233’9,238’5,078’5,082’5’01/18/25 Isolated (02/16/25)
Bel Dd 9,263’9,283’5,099’5,144’20’01/15/25 Isolated (01/17/25)
Bel De 9,319’9,339’5,140’5,155’20’01/15/25 Isolated (01/17/25)
Bel Df 9,350’9,367’5,163’5,176’17’01/14/25 Isolated (01/17/25)
Bel Ea 9,390’9,400’5,193’5,201’10’01/14/25 Isolated (01/16/25)
Bel Eb 9,432’9,452’5,225’5,240’20’01/13/25 Isolated (01/16/25)
Bel Ha 9,795’9,811’5,519’5,533’16’01/11/25 Isolated (01/13/25)
Bel Jc 10,173’10,179’5,848’5,853’6’11/10/24 Isolated (01/08/25)
Bel Ma 10,386’10,396’6,035’6,044’10’11/9/24 Isolated (01/08/25)
Bel Mb 10,408’10,414’6,054’6,060’6’11/9/24 Isolated (01/08/25)
Bel Mc 10,424’10,444’6,068’6,086’20’10/31/24 Isolated (01/08/25)
Bel N 10,460’10,464’6,100’6,104’4’10/29/24 Isolated (01/08/25)
Bel Oa 10,502’10,508’6,137’6,142’6’10/29/24 Isolated (01/08/25)
Bel Ob 10,516’10,530’6,147’6,162’14’10/29/24 Isolated (01/08/25)
Bel P 10,578’10,584’6,204’6,210’6’10/28/24 Isolated (10/29/24)
Bel Pb 10,602’10,608’6,226’6,231’6’10/28/24 Isolated (10/29/24)
Bel Pc 10,629’10,643’6,249’6,262’14’10/17/24 Isolated (10/29/24)
Bel Qa 10,678’10,684’6,293’6,298’6’10/17/24 Isolated (10/27/24)
Bel Qb 10,742’10,756’6,349’6,362’14’10/17/24 Isolated (10/27/24)
Bel Qc 10,777’10,783’6,380’6,386’6’10/17/24 Isolated (10/27/24)
Bel Ra 10,825’10,835’6,423’6,432’10’10/17/24 Isolated (10/27/24)
Bel Rb 10,844’10,850’6,440’6,445’6’10/17/24 Isolated (10/27/24)
Bel Rc 10,884’10,890’6,475’6,480’6’10/17/24 Isolated (10/27/24)
Bel Rd 10,918’10,928’6,505’6,514’10’10/17/24 Isolated (10/27/24)
Bel Sa 10,946’10,956’6,530’6,539’10’10/16/24 Isolated (10/27/24)
Bel S 11,056’11,062’6,627’6,632’6’10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’6,728’10’10/16/24 Isolated (10/27/24)
Well Prognosis
Well: NCIU A-21
Date: 7/29/25
BOPE Schematic
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.
From:Rixse, Melvin G (OGC)
To:Sean McLaughlin
Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Roby, David S (OGC)
Subject:20250729 1540 North Cook Inlet Unit A-21 Plug for Redrill Sundry 325-410 PTD (224-086)
Date:Tuesday, July 29, 2025 3:42:16 PM
Sean,
AOGCC will request assurance of cement across the two sets of perforations 6424’
MD - 6414’ MD and 6373’ MD – 6383’ MD.
If Hilcorp has no injectivity, laying in cement above a retainer set at 5600’ MD without
covering the exposed perforations is insufficient.
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. Dewhurst, Davies, Roby
From: Sean McLaughlin <sean.mclaughlin@hilcorp.com>
Sent: Tuesday, July 29, 2025 10:37 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: A-21A abandonment (225-075)
Mel,
Prior to setting the BPV and nipple down of A-21 we attempted a bullhead kill through the 4-
1/2” tubing. We were unable to achieve a significant injection rate at 3000 psi and suspect the
Sterling sands are plugged with fill. Currently two 10’ Sterling intervals are open. There is a
cast iron plug with cement on top set at the top of the Beluga interval.
The plan was to pump 50 bbls of cement below the retainer and 30 bbls above the retainer.
Would it be permissible to run the retainer, pump cement to the stinger then attempt to
squeeze or breakdown with the understanding that there may be little to no cement below the
retainer? Then lay in the remaining cement on top of the retainer. 80 bbls inside of 9-5/8” is
around 1000’ of cement.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Manager
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
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):
11,394 10,163
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: Sean Mclaughlin
Contact Email:sean.mclaughlin@hilcorp.com
Contact Phone:907-223-6784
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:
North Cook Inlet Tertiary System Gas Same
6,925 6450'3731'1,223psi 6450' top plug
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):
Drilling Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
224-086
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-00-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21
Length Size
Proposed Pools:
L-80
TVD Burst
5,766
8,430psi
MD
1,630psi
6,870psi
384'
3,501'
384'
5,909'
30"
9-5/8"
384'
5,909'
6373-6424
5,655'
3706-3729
6,923'4-1/2"11,391'
7/26/2025
4-1/2"
LTP & Baker TE-5 5,758 (MD) 3,437 (TVD) & 446 (MD) 446 (TVD)
Perforation Depth MD (ft):
m
n
P
s
2
6
5
6
t c
N
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 3:48 pm, Jul 09, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.07.09 15:16:33 -
08'00'
Sean
McLaughlin
(4311)
325-410
MGR14JULY25 A.Dewhurst 21JUL25
10-407
DSR-7/16/25
21 July 2026
* BOPE pressue test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC.
* AOGCC to witness tag a pressure test of TOC ~
JLC 7/21/2025
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.07.21 16:25:25 -08'00'07/21/25
RBDMS JSB 072225
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
Well Name:NCIU A-21 API Number:50-883-20199-00-00
Current Status:Plug For Redrill
Estimated Start Date:7/26/25 Rig:Spartan 151
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-086
First Call Engineer:Sean Mclaughlin 907-223-6784
Second Call Engineer
AFE Number:
Attachments:
1.Current Schematic
2.Proposed Schematic
3.Proposed Operations
4.BOPE Schematic
_____________________________________________________________________________________
Updated By: JLL 04/29/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
10
13
14
15
12
11
6
7
8
9
1
2
Sterling
Sands
3/4/5
Bel T
Bel Q
Bel S
Bel R
Bel P
Bel N
Bel O
Bel M
Bel J
Bel H
Bel E
Bel D
Bel B
Bel C
Bel D
Bel A
C I
C I
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’ 446' 6.620" Baker TE S-5 SSSV
2 1008’ 1,006' ES Cementer
3 5,711’ 3,417' 3.813" X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’ 3,437' 3.958" Liner hanger / LTP Assembly
5 5,766’ 3,440' 3.958" Seal Stem
6 6,450’ 3,741’ - CIBP (04/01/25)
7 7,050’ 4,001’ - CIBP (03/30/25)
8 7,460’ 4,173’ - CIBP (03/29/25)
9 8,630’ 4,700’ - CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’ 5,090’ - CIBP (01/17/25)
11 9,380’ 5,186’ - CIBP (01/16/25)
12 9,775’ 5,502’ - CIBP (01/13/25)
13 10,130’ 5,810’ - CIBP (01/08/25)
14 10,570’ 6,197’ - CIBP (10/29/24)
15 10,670’ 6,286’ - CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’ 6,383’ 3,706’ 3,711’ 10’ 04/04/25 Open
Aa 6,414’ 6,424’ 3,725’ 3,729’ 10’ 04/01/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’ 2,012' 3.833" GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’ 3,395' 3.833" GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’ 12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
Updated By: JLL 04/29/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’ 6,467’ 3,744’ 3,749’ 10’ 03/31/25 Isolated (04/01/25)
B 6,561’ 6,571’ 3,791’ 3,796’ 10’ 03/31/25 Isolated (04/01/25)
CI 1 7,063’ 7,073’ 4,006’ 4,010’ 10’ 03/29/25 Isolated (03/30/25)
CI 2 7,274’ 7,284’ 4,095’ 4,100’ 10’ 03/29/25 Isolated (03/30/25)
CI 3 7,474’ 7,484’ 4,179’ 4,183’ 10’ 02/19/25 Isolated (03/29/25)
CI 8 8,226’ 8,234’ 4,508’ 4,511’ 8’ 02/19/25 Isolated (03/29/25)
CI 12a 8,564’ 8,572’ 4,666’ 4,670’ 8’ 02/18/25 Isolated (03/29/25)
Bel Aa 8,634’ 8,662’ 4,702’ 4,717’ 28’ 01/21/25 Isolated (02/16/25)
Bel Ba 8,833’ 8,847’ 4,814’ 4,822’ 14’ 01/20/25 Isolated (02/16/25)
Bel Bb 8,856’ 8,872’ 4,828’ 4,837’ 16’ 01/20/25 Isolated (02/16/25)
Bel Bd 8,954’ 8,965’ 4,889’ 4,896’ 11’ 01/19/25 Isolated (02/16/25)
Del Be 9,000’ 9,004’ 4,919’ 4,922’ 4’ 01/19/25 Isolated (02/16/25)
Bel Bf 9,022’ 9,028’ 4,934’ 4,938’ 6’ 01/19/25 Isolated (02/16/25)
Bel Ca 9,064’ 9,074’ 4,962’ 4,968’ 10’ 01/18/25 Isolated (02/16/25)
Bel Cb 9,084’ 9,094’ 4,975’ 4,982’ 10’ 01/18/25 Isolated (02/16/25)
Bel Cc 9,103’ 9,113’ 4,988’ 4,995’ 10’ 01/18/25 Isolated (02/16/25)
Bel Da 9,200’ 9,210’ 5,055’ 5,062’ 10’ 01/18/25 Isolated (02/16/25)
Bel Db 9,218’ 9,224’ 5,068’ 5,072’ 6’ 01/18/25 Isolated (02/16/25)
Bel Dc 9,233’ 9,238’ 5,078’ 5,082’ 5’ 01/18/25 Isolated (02/16/25)
Bel Dd 9,263’ 9,283’ 5,099’ 5,144’ 20’ 01/15/25 Isolated (01/17/25)
Bel De 9,319’ 9,339’ 5,140’ 5,155’ 20’ 01/15/25 Isolated (01/17/25)
Bel Df 9,350’ 9,367’ 5,163’ 5,176’ 17’ 01/14/25 Isolated (01/17/25)
Bel Ea 9,390’ 9,400’ 5,193’ 5,201’ 10’ 01/14/25 Isolated (01/16/25)
Bel Eb 9,432’ 9,452’ 5,225’ 5,240’ 20’ 01/13/25 Isolated (01/16/25)
Bel Ha 9,795’ 9,811’ 5,519’ 5,533’ 16’ 01/11/25 Isolated (01/13/25)
Bel Jc 10,173’ 10,179’ 5,848’ 5,853’ 6’ 11/10/24 Isolated (01/08/25)
Bel Ma 10,386’ 10,396’ 6,035’ 6,044’ 10’ 11/9/24 Isolated (01/08/25)
Bel Mb 10,408’ 10,414’ 6,054’ 6,060’ 6’ 11/9/24 Isolated (01/08/25)
Bel Mc 10,424’ 10,444’ 6,068’ 6,086’ 20’ 10/31/24 Isolated (01/08/25)
Bel N 10,460’ 10,464’ 6,100’ 6,104’ 4’ 10/29/24 Isolated (01/08/25)
Bel Oa 10,502’ 10,508’ 6,137’ 6,142’ 6’ 10/29/24 Isolated (01/08/25)
Bel Ob 10,516’ 10,530’ 6,147’ 6,162’ 14’ 10/29/24 Isolated (01/08/25)
Bel P 10,578’ 10,584’ 6,204’ 6,210’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pb 10,602’ 10,608’ 6,226’ 6,231’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pc 10,629’ 10,643’ 6,249’ 6,262’ 14’ 10/17/24 Isolated (10/29/24)
Bel Qa 10,678’ 10,684’ 6,293’ 6,298’ 6’ 10/17/24 Isolated (10/27/24)
Bel Qb 10,742’ 10,756’ 6,349’ 6,362’ 14’ 10/17/24 Isolated (10/27/24)
Bel Qc 10,777’ 10,783’ 6,380’ 6,386’ 6’ 10/17/24 Isolated (10/27/24)
Bel Ra 10,825’ 10,835’ 6,423’ 6,432’ 10’ 10/17/24 Isolated (10/27/24)
Bel Rb 10,844’ 10,850’ 6,440’ 6,445’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rc 10,884’ 10,890’ 6,475’ 6,480’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rd 10,918’ 10,928’ 6,505’ 6,514’ 10’ 10/17/24 Isolated (10/27/24)
Bel Sa 10,946’ 10,956’ 6,530’ 6,539’ 10’ 10/16/24 Isolated (10/27/24)
Bel S 11,056’ 11,062’ 6,627’ 6,632’ 6’ 10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’ 6,728’ 10’ 10/16/24 Isolated (10/27/24)
_____________________________________________________________________________________
Updated By: CJD 7/9/25
Proposed SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
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 5,909’
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”5,736’11,391’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 1008’1,006'ES Cementer
2 1,600’1,554’Whipstock
3 5,600’3,372'Cement Retainer w 400’ cmt on top
4 5,758’3,437'3.958"Liner hanger / LTP Assembly
5 5,766’3,440'3.958"Seal Stem
6 6,450’3,741’-CIBP (04/01/25)
7 7,050’4,001’-CIBP (03/30/25)
8 7,460’4,173’-CIBP (03/29/25)
9 8,630’4,700’-CIBP (02/16/25) w/31’ cement (TOC 8,599’)
10 9,250’5,090’-CIBP (01/17/25)
11 9,380’5,186’-CIBP (01/16/25)
12 9,775’5,502’-CIBP (01/13/25)
13 10,130’5,810’-CIBP (01/08/25)
14 10,570’6,197’-CIBP (10/29/24)
15 10,670’6,286’-CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ster Stray 4 6,373’6,383’3,706’3,711’10’04/04/25 Plug
Aa 6,414’6,424’3,725’3,729’10’04/01/25 Plug
Isolated Perforation Details on Page 2
FISH DETAILS
10,163’12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2”Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384'GCBD with RA tag in collar
10,387'GCBD with RA tag in collar
Updated By: JLL 7/9/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Ab 6,457’6,467’3,744’3,749’10’03/31/25 Isolated (04/01/25)
B 6,561’6,571’3,791’3,796’10’03/31/25 Isolated (04/01/25)
CI 1 7,063’7,073’4,006’4,010’10’03/29/25 Isolated (03/30/25)
CI 2 7,274’7,284’4,095’4,100’10’03/29/25 Isolated (03/30/25)
CI 3 7,474’7,484’4,179’4,183’10’02/19/25 Isolated (03/29/25)
CI 8 8,226’8,234’4,508’4,511’8’02/19/25 Isolated (03/29/25)
CI 12a 8,564’8,572’4,666’4,670’8’02/18/25 Isolated (03/29/25)
Bel Aa 8,634’8,662’4,702’4,717’28’01/21/25 Isolated (02/16/25)
Bel Ba 8,833’8,847’4,814’4,822’14’01/20/25 Isolated (02/16/25)
Bel Bb 8,856’8,872’4,828’4,837’16’01/20/25 Isolated (02/16/25)
Bel Bd 8,954’8,965’4,889’4,896’11’01/19/25 Isolated (02/16/25)
Del Be 9,000’9,004’4,919’4,922’4’01/19/25 Isolated (02/16/25)
Bel Bf 9,022’9,028’4,934’4,938’6’01/19/25 Isolated (02/16/25)
Bel Ca 9,064’9,074’4,962’4,968’10’01/18/25 Isolated (02/16/25)
Bel Cb 9,084’9,094’4,975’4,982’10’01/18/25 Isolated (02/16/25)
Bel Cc 9,103’9,113’4,988’4,995’10’01/18/25 Isolated (02/16/25)
Bel Da 9,200’9,210’5,055’5,062’10’01/18/25 Isolated (02/16/25)
Bel Db 9,218’9,224’5,068’5,072’6’01/18/25 Isolated (02/16/25)
Bel Dc 9,233’9,238’5,078’5,082’5’01/18/25 Isolated (02/16/25)
Bel Dd 9,263’9,283’5,099’5,144’20’01/15/25 Isolated (01/17/25)
Bel De 9,319’9,339’5,140’5,155’20’01/15/25 Isolated (01/17/25)
Bel Df 9,350’9,367’5,163’5,176’17’01/14/25 Isolated (01/17/25)
Bel Ea 9,390’9,400’5,193’5,201’10’01/14/25 Isolated (01/16/25)
Bel Eb 9,432’9,452’5,225’5,240’20’01/13/25 Isolated (01/16/25)
Bel Ha 9,795’9,811’5,519’5,533’16’01/11/25 Isolated (01/13/25)
Bel Jc 10,173’10,179’5,848’5,853’6’11/10/24 Isolated (01/08/25)
Bel Ma 10,386’10,396’6,035’6,044’10’11/9/24 Isolated (01/08/25)
Bel Mb 10,408’10,414’6,054’6,060’6’11/9/24 Isolated (01/08/25)
Bel Mc 10,424’10,444’6,068’6,086’20’10/31/24 Isolated (01/08/25)
Bel N 10,460’10,464’6,100’6,104’4’10/29/24 Isolated (01/08/25)
Bel Oa 10,502’10,508’6,137’6,142’6’10/29/24 Isolated (01/08/25)
Bel Ob 10,516’10,530’6,147’6,162’14’10/29/24 Isolated (01/08/25)
Bel P 10,578’10,584’6,204’6,210’6’10/28/24 Isolated (10/29/24)
Bel Pb 10,602’10,608’6,226’6,231’6’10/28/24 Isolated (10/29/24)
Bel Pc 10,629’10,643’6,249’6,262’14’10/17/24 Isolated (10/29/24)
Bel Qa 10,678’10,684’6,293’6,298’6’10/17/24 Isolated (10/27/24)
Bel Qb 10,742’10,756’6,349’6,362’14’10/17/24 Isolated (10/27/24)
Bel Qc 10,777’10,783’6,380’6,386’6’10/17/24 Isolated (10/27/24)
Bel Ra 10,825’10,835’6,423’6,432’10’10/17/24 Isolated (10/27/24)
Bel Rb 10,844’10,850’6,440’6,445’6’10/17/24 Isolated (10/27/24)
Bel Rc 10,884’10,890’6,475’6,480’6’10/17/24 Isolated (10/27/24)
Bel Rd 10,918’10,928’6,505’6,514’10’10/17/24 Isolated (10/27/24)
Bel Sa 10,946’10,956’6,530’6,539’10’10/16/24 Isolated (10/27/24)
Bel S 11,056’11,062’6,627’6,632’6’10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’6,728’10’10/16/24 Isolated (10/27/24)
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
1. 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
2. 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.
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
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 ч 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
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
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.
3. 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.
4. 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 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.
AOGCC to witness tag and pressure test of TOC ~
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
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 under drilling permit.
Well Prognosis
Well: NCIU A-21
Date: 7/9/25
BOPE Schematic
Sundry Application
Well Name______________________________
(PTD _________; Sundry _________)
Plug for Re-drill Well
Workflow
This process is used to identify wells that are suspended for a very short time prior to being
re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and
assigned a current status of "Suspended."
Step Task Responsible
1 The initial reviewer will check to ensure that the "Plug for Redrill" box in
the upper left corner of Form 10-403 is checked. If the "Abandon" or
"Suspend" boxes are also checked, cross out that erroneous entry and
initial it on the Form 10-403.
Geologist
2 If the “Abandon” box is checked in Box 15 (Well Status after proposed
work) the initial reviewer will cross out that checkbox and instead, check
the "Suspended" box and initial those changes.
Geologist
The drilling engineer will serve as quality control for steps 1 and 2.
Petroleum
Engineer
(QC)
3 When the RA2 receives a Form 10-403 with a check in the "Plug for
Redrill" box, they will enter the Typ_Work code "IPBRD" into the
History tab for the well in RBDMS. This code automatically generates
a comment in the well history that states "Intent: Plug for Redrill."
Research
Analyst 2
4 When the RA2 receives Form 10-407, they will check the History tab
in RBDMS for the IPBRD code. If IPBRD is present and there is no
evidence that a subsequent re-drill has been completed, the RA2 will
assign a status of SUSPENDED to the well bore in RBDMS. The RA2
will update the status on the 10-407 form to SUSPENDED, and date
and initial this change.
If the RA2 does not see the "Intent: Plug for Redrill" comment or code,
they will enter the status listed on the Form 10-407 into RBDMS.
Research
Analyst 2
5 When the Form 10-407 for the redrill is received, the RA2 will change the
original well's status from SUSPENDED to ABANDONED.
Research
Analyst 2
6 The first week of every January and July, the RA2 and a Geologist or
Reservoir Engineer will check the "Well by Type Work Outstanding"
user query in RBDMS to ensure that all Plug for Redrill sundried wells
have been updated to reflect current status.
At this same time, they will also review the list of suspended wells for
accuracy and assign expiration dates as needed.
Research
Analyst 2
Geologist or
Reservoir
Engineer
A.Dewhurst 21JUL25
325-410224-086
NCIU A-21
A.Dewhurst 21JUL25
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: 4/22/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#2025022
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL
BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf
BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP
BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf
MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL
MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL
MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut
NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf
NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf
PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile
HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL
HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40328
T40329
T40330
T40331
T40332
T40333
T40334
T40335
T40336
T40337
T40338
T40339
NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.28 08:42:09 -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: 4/10/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#2025010
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 211-26 50283201280000 208112 1/27/2025 AK E-LINE PPROF
T40287
END 1-41 50029217130000 187032 3/13/2025 HALLIBURTON MFC40
T40288
END 2-14 50029216390000 186149 3/12/2025 HALLIBURTON MFC40
T40289
END 3-33A 50029216680100 203215 3/23/2025 HALLIBURTON COILFLAG
T40290
GP AN-17A 50733203110100 213049 12/29/2024 AK E-LINE Perf
T40291
KALOTSA 3 50133206610000 217028 3/3/2025 AK E-LINE PPROF
T40292
KU 12-17 50133205770000 208089 1/28/2025 AK E-LINE Perf
T40293
MPI 2-14 50029216390000 186149 2/17/2025 AK E-LINE Plug/Cement
T40294
NCIU A-21 50883201990000 224086 3/28/2025 AK E-LINE Plug-Perf
T40295
ODSN-25 50703206560000 212030 3/7/2025 HALLIBURTON CORRELATION
T40296
PBU 02-08B 50029201550200 198095 3/17/2025 HALLIBURTON RBT
T40297
PBU D-08B 50029203720200 225007 3/22/2025 HALLIBURTON RBT
T40298
PBU J-25B 50029217410200 224134 3/10/2025 HALLIBURTON RBT
T40299
PBU K-12D 50029217590400 224099 3/18/2025 HALLIBURTON RBT
T40300
PBU K-19B 50029225310200 215182 3/27/2025 HALLIBURTON RBT
T40301
PBU L1-15A 50029219950100 203120 3/27/2025 HALLIBURTON PPROF
T40302
PBU M-207 50029238070000 224141 3/18/2025 HALLIBURTON IPROF
T40303
PBU P1-04 50029223660000 193063 3/28/2025 HALLIBURTON PPROF
T40304
PBU W-220A 50029234320100 224161 3/11/2025 HALLIBURTON RBT
T40305
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40295NCIU A-21 50883201990000 224086 3/28/2025 AK E-LINE Plug-Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.10 13:48:56 -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: 3/2/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250302
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
CLU 11 50133205590000 206058 2/19/2025 AK E-LINE CBL,CIBP
CLU 11 50133205590000 206058 2/13/2025 AK E-LINE CIBP
END 1-65A 50029226270100 203212 1/27/2025 HALLIBURTON COILFLAG
END 2-56A 50029228630100 198058 2/6/2025 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 2/2/2025 HALLIBURTON PPROF
MPU F-29 50029226880000 196117 1/31/2025 HALLIBURTON MFC24
MPU L-02A 50029219980100 209147 2/17/2025 READ CaliperSurvey
MPU L-36 50029227940000 197148 1/18/2025 HALLIBURTON MFC24
MPU R-144 50029238090000 224148 2/11/2025 HALLIBURTON WFL-TMD3D
NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf
ODSN-25 50703206560000 212030 2/16/2025 READ MemoryLeakPoint
PBU 06-05A 50029202980100 224115 1/15/2025 BAKER MRPM
PBU 06-15A 50029204590200 224108 12/27/2024 HALLIBURTON RBT
PBU 06-16B 50029204600200 223072 1/25/2025 BAKER MRPM
PBU B-12B 50029203320200 224133 1/19/2025 BAKER MRPM
PBU S-126B 50029233630200 224084 2/7/2025 HALLIBURTON RBT
PBU V-105 50029230970000 202131 2/9/2025 HALLIBURTON IPROF
PBU W-01A 50029218660100 203176 1/19/2025 AK E-LINE CBL
PBU W-01B 50029218660200 224149 1/28/2025 HALLIBURTON RBT
PCU 02A 50283200220100 224110 1/24/2025 AK E-LINE CIBP
Please include current contact information if different from above.
T40161
T40161
T40162
T40163
T40164
T40165
T40166
T40167
T40168
T40169
T40170
T40171
T40172
T40173
T40174
T40175
T40176
T40177
T40178
T40179
NCIU A-21 50883201990000 224086 2/18/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.03.03 10:15:14 -09'00'
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
30" - 384'
4-1/2"L-80 6,923'
4-1/2"L-80 3,440'
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 0540
1/21/2025 24
Flow Tubing
0
552
N/A5520
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
11,391'3,427'
-384'
Water-Bbl:
PRODUCTION TEST
10/30/2024
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation details ***
Gas-Oil Ratio:
Surface
5,736'
Stg 1 L - 802 sx / T - 113 sx
AMOUNT
PULLED
334163
334659
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.
PACKER SET (MD/TVD)
Surface
Conductor
12.6#
GRADE CEMENTING RECORD
2592823
SETTING DEPTH TVD
2594332
TOP HOLE SIZE
CBL 10-8-24, LWD (DGR, EWR-P4, ADR, CTN, ALD, PWD, DDSR), Geotap, Tie In/Perf Logs
Tertiary System Gas Pool
ADL 17589 / ADL 37831
N/A
N/A
446' MD / 446' TVD
11,394' MD / 6,925' TVD
9,250' MD / 5,090' TVD
406' FNL, 1954' FEL, Sec 31, T12N, R9W, SM, AK
1110' FSL, 1475' FEL, Sec 30, T12N, R9W, SM, AK
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
332001 2586725
50-883-20199-00-00August 9, 2024
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
10/16/2024 224-086 / 324-528
N/A
NCIU A-21August 30, 20241254' FNL, 982' FWL, Sec 6, T11N, R9W, SM, AK
126.6'
BOTTOMCASINGWT. PER
FT.
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,
L - 843 sx / T - 180 sx8-1/2"
TUBING RECORD
Tieback Assy.5,766'
Stg 2 L - 987 sx
Surface Tieback
Driven
12.6#
N/A
SIZE DEPTH SET (MD)
9-5/8"47#L-80 Surface 5,909'Surface 3,499'12-1/4"
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
G
s d 1
0 p
dB P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
Received by J. Brooks on
2/11/2025 at 3:23PM
Completed
10/16/2024
JSB
RBDMS JSB 021225
GDSR-4/7/25BJM 10/6/25
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel Aa 8,634' 4,702'
5983' 3533'
6016' 3548'
6100' 3585'
8623' 4696'
9050' 4952'
9381' 5186'
9696' 5435'
10068' 5756'
10382' 6031'
10457' 6097'
10495' 6131'
10933' 6518'
Beluga T
11132' 6694'
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:
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt reports
Authorized Title: Drilling Manager
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 M
Bel A
Sterling X
Bel C
Bel J
Sterling Y
Sterling Z
Bel E
Bel G
Bel N
Bel O
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
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: 2025.02.11 15:20:44 -
09'00'
Sean
McLaughlin
(4311)
_____________________________________________________________________________________
Updated By: JLL 01/23/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
6
9
10
11
8
7
1
2
3/4/5
Bel T
Bel Q
Bel S
Bel R
Bel P
Bel N
Bel O
Bel M
Bel J
Bel H
Bel E
Bel D
Bel B
Bel C
Bel D
Bel A
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”5,736’11,391’
TUBING DETAIL
4-1/2"Prod Tieback 12.6 L-80 IBT-M 3.958”Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’446'6.620"Baker TE S-5 SSSV
2 1008’1,006'ES Cementer
3 5,711’3,417'3.813"X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’3,437'3.958"Liner hanger / LTP Assembly
5 5,766’3,440'3.958"Seal Stem
6 9,250’5,090’-CIBP (01/17/25)
7 9,380’5,186’-CIBP (01/16/25)
8 9,775’5,502’-CIBP (01/13/25)
9 10,130’5,810’-CIBP (01/08/25)
10 10,570’6,197’-CIBP (10/29/24)
11 10,670’6,286’-CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Bel Aa 8,634’8,662’4,702’4,717’28’01/21/25 Open
Bel Ba 8,833’8,847’4,814’4,822’14’01/20/25 Open
Bel Bb 8,856’8,872’4,828’4,837’16’01/20/25 Open
Bel Bd 8,954’8,965’4,889’4,896’11’01/19/25 Open
Del Be 9,000’9,004’4,919’4,922’4’01/19/25 Open
Bel Bf 9,022’9,028’4,934’4,938’6’01/19/25 Open
Bel Ca 9,064’9,074’4,962’4,968’10’01/18/25 Open
Bel Cb 9,084’9,094’4,975’4,982’10’01/18/25 Open
Bel Cc 9,103’9,113’4,988’4,995’10’01/18/25 Open
Bel Da 9,200’9,210’5,055’5,062’10’01/18/25 Open
Bel Db 9,218’9,224’5,068’5,072’6’01/18/25 Open
Bel Dc 9,233’9,238’5,078’5,082’5’01/18/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’2,012'3.833"GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’3,395'3.833"GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2”Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384'GCBD with RA tag in collar
10,387'GCBD with RA tag in collar
Updated By: JLL 01/23/25
SCHEMATIC
North Cook Inlet Unit
Well:NCIU A-21
Date Completed: 9/7/2024
PTD:224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Bel Dd 9,263’9,283’5,099’5,144’20’01/15/25 Isolated (01/17/25)
Bel De 9,319’9,339’5,140’5,155’20’01/15/25 Isolated (01/17/25)
Bel Df 9,350’9,367’5,163’5,176’17’01/14/25 Isolated (01/17/25)
Bel Ea 9,390’9,400’5,193’5,201’10’01/14/25 Isolated (01/16/25)
Bel Eb 9,432’9,452’5,225’5,240’20’01/13/25 Isolated (01/16/25)
Bel Ha 9,795’9,811’5,519’5,533’16’01/11/25 Isolated (01/13/25)
Bel Jc 10,173’10,179’5,848’5,853’6’11/10/24 Isolated (01/08/25)
Bel Ma 10,386’10,396’6,035’6,044’10’11/9/24 Isolated (01/08/25)
Bel Mb 10,408’10,414’6,054’6,060’6’11/9/24 Isolated (01/08/25)
Bel Mc 10,424’10,444’6,068’6,086’20’10/31/24 Isolated (01/08/25)
Bel N 10,460’10,464’6,100’6,104’4’10/29/24 Isolated (01/08/25)
Bel Oa 10,502’10,508’6,137’6,142’6’10/29/24 Isolated (01/08/25)
Bel Ob 10,516’10,530’6,147’6,162’14’10/29/24 Isolated (01/08/25)
Bel P 10,578’10,584’6,204’6,210’6’10/28/24 Isolated (10/29/24)
Bel Pb 10,602’10,608’6,226’6,231’6’10/28/24 Isolated (10/29/24)
Bel Pc 10,629’10,643’6,249’6,262’14’10/17/24 Isolated (10/29/24)
Bel Qa 10,678’10,684’6,293’6,298’6’10/17/24 Isolated (10/27/24)
Bel Qb 10,742’10,756’6,349’6,362’14’10/17/24 Isolated (10/27/24)
Bel Qc 10,777’10,783’6,380’6,386’6’10/17/24 Isolated (10/27/24)
Bel Ra 10,825’10,835’6,423’6,432’10’10/17/24 Isolated (10/27/24)
Bel Rb 10,844’10,850’6,440’6,445’6’10/17/24 Isolated (10/27/24)
Bel Rc 10,884’10,890’6,475’6,480’6’10/17/24 Isolated (10/27/24)
Bel Rd 10,918’10,928’6,505’6,514’10’10/17/24 Isolated (10/27/24)
Bel Sa 10,946’10,956’6,530’6,539’10’10/16/24 Isolated (10/27/24)
Bel S 11,056’11,062’6,627’6,632’6’10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’6,728’10’10/16/24 Isolated (10/27/24)
Page 1/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:8/2/2024 End Date:
Report Number
1
Report Start Date
8/2/2024
Report End Date
8/3/2024
Operation
Paint platform shakers. continue to pressure wash in platform shaker tank. R/D flow line f/ rig floor t/ RPM tank. Transvese rig package center of white iron and secure
same. Install jacks and attempt to skid rig south. Found leak on cylinder. Change out same.
Finish prepare skid jacks. PJSM. Skid rig south in preparation to grab RPM tank. Remove flow line, walkways. Continue skid rig package to south hand rail.
Install earthquake clamps, pump out and wash out mud catch tank. Pump out water F/ slope tank to skimmer tank. Break loose all service lines. Pressure wash platform
tank roof.
Remove RPM roof. Remove flow line to shakers, stairs, walkways, Stow shunt line and L.P mud return hoses inside platform tank. Ready all short lines and connections
in baskets to be sent in. Secure items stowed on platform tank with banding material.
Attempt to pull boat onto location 3x to backload equipment. Wind and seas to rough. Continue preparing equipment to send in. Re-arrange equipment on deck. Pull
service hoses f/ rig to plaftorm.
Report Number
2
Report Start Date
8/3/2024
Report End Date
8/4/2024
Operation
Transverse upper sub-base to west. Backload RPM tank and assosiated equpiment. Remove storm clamps, stairs and skid HAK deck to the south. Move bang box
electrical panel. Clean high and low suctions on pits/mud pumps.
Break bolts and load out first section of HAK deck. Skid green iron to south, disasemble green iron and load on boat. Continue cleaning shakers and mud pits. R/D rig
floor extension control cables.
Clear top of welding shop roof in preparation for rig package to skid. Clean platform deck. Transverse sub-base to center over white iron. Skid rig package to north
towards leg 1. Take on drill water to pits. Lower starter head for A-21 well into wellbay for welders to weld onto conductor.
Continue skidding rig package to north towards leg #1 slot 5 over well A-21. Inspect fluid ends of mud pumps. Clean up main dec k around leg #2. Welders preping to cut
platform welding shop roof for transverse beams. R/U service lines to rig floor. Install storm clamps on white iron.
Report Number
3
Report Start Date
8/4/2024
Report End Date
8/5/2024
Operation
Clean main deck of platform on leg 2. Run and plug in electrical service lines for rig package. Install brass wear plate under port aft Cantilever beam. Install storm clamps
on transverse skid of sub-base. Fill mud pits 1 &2 with drill water to build spud mud. Clean out de-gasser. R/U and begin removing lower section flowline f/ rig floor.
Continue inspecting fluid ends on mud pumps. Welders modify top of platform welding shop roof for rig package transverse beams.
Continue removing flow line f/rig package; Install blind flange w/ 2" valve to bottom and tighten same. Offload and install support beams across cantilever lower support
beams. Clean and clear work area. Pull baffle plates f/ degasser. clean out solids and inspect internal componets. Change washed valve and seats in mud pumps. Weld
out starter head and 4" side ports to slot #5 per welding procedure.
Secure beams with boiler clamps and studs. Install HAK deck base support on beams. Reassemble degasser. Inspect desilter and desander cones. Start building 8.8ppg
spud mud. Transverse white iron to east into cut slots of welding shop. Prep upper rig package transverse rails to transverse east. Drill holes in Cantilever support pads to
install securing bolts.
Transverse upper rig package to east to center over A-21 conductor. Remove skid cylinders on sub-base. Transfer MWD shack along side sub-base. Welders work on
installing flow line for rig floor. Start install south side storm clamps on sub-base. Organize decks in preparation for offloading of boat.
Report Number
4
Report Start Date
8/5/2024
Report End Date
8/6/2024
Operation
Build 8.8ppg spud mud. Offload HAK deck and install on cantilever beams. Secure HAK to beams with bolts. Install V-door. Safe out HAK deck with handrails. Install stair
way from upper pipe rack to HAK deck. Change main air line for rig package. Install access to rig floor.
Break down BOP's, remove annular and set on main deck. Set Single and double on deck and secure same. Remove hatch cover for A-21 and install slotted grating
cover. Welders install Tee to flow line and scalper shaker. Install flow line from rig floor to ditch of cantilever. P/U 20-3/4" riser installing on A-21 Starter head.
Torque slip on flange to starter head. R/U H.P mud line to rig floor and flood test riser. No visable leaks. P/U diverter annular w/ mud cross and slip on adapter. Inspect
quick connect on same. Continue building spud mud. Transfer mud to sand traps.
Install scaffolding in BOP mezzanine deck. Install 21-1/4" annular with tee on riser. Torque diverter Tee to recommeded specs. Install first joiint with valve of diverter line
to tee. Continue building spud mud. Cleaning and organizing around rig. Safe out misc areas on rig.
Daily Discharge: 0 bbls
Cumulative discharge: 0 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 0.0bbls
Report Number
5
Report Start Date
8/6/2024
Report End Date
8/7/2024
Operation
Clean under scalper shakers. Clean and safe out previous work area's. R/U BOP remote station on port upper cantilever. R/D lift cap on diverter. Blow down hydraulic
lines from top drive to HPU. Blow down hydraulic lines on ST-80 to HPU. Install air boot and bolt to top of diverter. Install dresser sleeve in rotary pan. Install bell nipple.
Build spud mud. Clean flow trough to rig shakers. Clean out HPU tank, Change oil and filter on HPU. R/U CMT lines to rig floor. Offload M/V Titan. Reconnect Pason
system, add gas trap in rig shakers.
Seal off top of pitcher nipple and flood test. Lower air boot leaking water; bump with air- good. Diverter valve leaking. Clean port flow ditch of old mud and cuttings. Clean
work areas around rig. Install niples and valves on flow line jets. Welders completed flow line to rig. Fill HPU with hydraulic oil and run same- good. Change out bad rig
service hoses f/ rig to rig package. Dress out shakers. Raise boom rest in place for diverter line. Check pre-charge in accumulator bottles.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151Permit to Drill (PTD) #:224-086
Wellbore API/UWI:50883201990000
Page 2/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Dress out scalper shakers w/ 10's and new rubber goods. Fill trip tank with salt water. Install flow 2 paddle into new flow line on HAK deck. Lwer and pull overboard shunt
line for scalper shakers. Clear plug from rig floor drain line. Pressure up accumulator unit and fuction diverter valve due to leak. Flood test diverter second time functioning
diverter valve. No joy. Drain diverter, Remove diverter valve from diverter line. Start break down knife valve removing seals to rebuild same.
Rebuild 16" diverter valve and reinstall same. Install 70' of 16" diverter line towards the south. Clean and organize rig. Afte r adding 70' to diverter line, 16" valve started
leaking. Repair same. Inspect pulsation dampeners on MP's.
Report Number
6
Report Start Date
8/7/2024
Report End Date
8/8/2024
Operation
Repair leak on diverter knife valve. Flood test diverter valve- good. Flood test rig floor flow line to mud pits, found leaks. Repair same- good. Perform function test on
diverter: annular: 23sec, diverter valve: 3 sec, System pressure: 3,100psi, Pressure after close: 2,100psi, 200psi recharge- 15 sec, Full system recover: 95 sec. Diverter
closest ignition source: >78 ft. Functioned remote panels- good. Function tested Mud pumps. AOGCC Rep Jim Regg waived witness.
Inspect and service top drive. Motor oil pressure alarm. Pump rotation backwards, swap same. Check rotation on blower- good. Change out saver sub. Check alignment
of top drive to center of rotary. Break bolts on derrick base, remove 1/2" shim f/ stb aft derrick leg. Retorque bolts.
Install new crown bell cable in derrick. Change crown bell and function test- good.
Clean and organize white iron sub-base, rig substructure and rig floor.
Troubleshoot pump pressure gauge in drillers console. Change pressure gauge and sensor. Flush line with fresh oil- good.
Rack back rental 5" DP stand on left side in derrick. P/U 5" HWDP off deck, torquing each connection and RIH. Utilize HW to center top drive with rotary. Loosen base
bolts and adjust shims. Verify top drive M/U at rotary and in derrick- good.
Finalize setting up gas antennas, greasing and storing target 90's. Pick up loose items in improper places.
P/U 5" HW and DP off deck, drifting, torquing to specs and racking back in derrick.
Report Number
7
Report Start Date
8/8/2024
Report End Date
8/9/2024
Operation
P/U 5" DP off deck, drift and torque to recommended specs, racking back in derrick.
Troubleshoot issues with ST-80.
P/U 5" DP off deck, drift and torque to recommeded specs , racking back in derrick. Short change crews.
Troubleshoot ST-80; back up clamp pin hole broke. R/U tongs. Change out pull sensor and hose. R/U spinner wrench and function same.
Familiarize drill crew on diverter system, walkthrough oncoming crew around to familiarize with rig setup.
P/U 5" DP off deck, drifting and torquing to recommended specs, racking back in derrick.
Conducted diverter and abandon drill with rig and platform crew at 17:00hrs. Full muster.
Offload M/V Titan. Adjust and measure crown saver vell in derrick. Remove hydraulic lines f/ ST-80 and prep for shipping. Gel gates in flow line ditch at rig shakers.
P/U 5" DP off deck, drifting and torquing to recommmended specs, racking back in derrick. TIH with wash tool and tag 6K down at 382.6' MD. POOH racking back 5" DP
in derrick. L/D 5" HW and wash tool. 62 stds 5" DP in derrick.
Install ST-80 in shipping carrier, remove F/ floor. Install Hawk Jaw pipe handler on floor and R/U same.
Report Number
8
Report Start Date
8/9/2024
Report End Date
8/10/2024
Operation
R/U Hawk Jaws. Function test- good. Remove spinner hawks from floor.
Hang off block. Slip and cut 106' of drill line. Function C-O-M after cut- good.
While servicing crown blocks, observed broken strands in air hoist cable. Slack hoist cable, inspecting same with several wires broken in a strand. Take out of service.
Inspect all sheaves in derrick; Found froze stand off sheaves for air hoist. Remove and free sheaves to prevent damaging cables, re-install same.
Finish installing stand off sheaves for air hoist. R/U AK E-line equpment, install sheave in derrick and secure same.
PJSM. P/U 8" TerraForce motor, M/U 12.25" tricone bit. M/U directional assembly per HES DD/MWD T/84' MD.
M/U std of 5" HWDP F/ derrick. Torque connection with rig tongs to 30kft-lbs, break out same. Torque connection with Hawk Jaws to 30Kft-lbs and compare break- good.
Position Hawk Jaw hangoff line in derrick to clear top drive.
TIH with 5" HWDP out of derrick on 12.25" directional assembly F/84' - T/356' MD. Break circulation at 200gpm with 20RPM, S/O and tag @383' MD with 5K down.
Displace well with 8.8ppg spud mud, taking returns overboar, 400gpm= 600psi, 15rpm= 500ft/lbs TQ.
Finish processing 9-5/8" surface CSG. Jt #77 off boat did not drift.
Drill F/ 383' to 388' MD, 400gpm= 600psi, 30rpm= 500ft/lbs TQ, WOB=0-2K.
P/U and RIH with Gyro survey. take 3 surveys 2x with multiple tool faces to verify tool operating correctly. Survey's inconsistant. E-line POOH to surface, check tools-
good. RIH and take 3 surveys 2x with consistant results.
Slide/Drill 12.25" surface section F/388' - T/449' MD. 400gpm= 630psi, 30rpm= 500ft/lbs TQ, 0-4K WOB, F/O= 41%, P/U=80K, S/O= 80K, ROTW=82K. Taking Gyro
surveys every 30' after drilling each std.
Slide/Drill 12.25" surface section F/449' - T/880' MD. 480gpm= 870psi, 40rpm= 800ft/lbs TQ, 0-10K WOB, F/O= 42%, P/U=90K, S/O= 90K, ROTW=90K. Taking Gyro
surveys every 30' after drilling each std.
Distance to Plan: 3.26', 1.15' High, 3.0' Right.
Daily Discharge: 325 bbls
Cumulative discharge: 325 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 0.0bbls
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 3/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Report Number
9
Report Start Date
8/10/2024
Report End Date
8/11/2024
Operation
Slide/Drill 12.25" surface section F/880' - T/1,003' MD. 475gpm= 860psi, 0-12K WOB, F/O= 52.5% , 8.9ppg MW. P/U=90K, S/O= 90K, ROTW= 90K. Taking Gyro surveys
every 30' after each drilled stand.
CBU at 1,003' MD recirpocating pipe . 475gpm= 856psi, F/O= 45.5%. Take gyro surveys every 30'. Pump up survey with on HES MWD.
Pump out of hole racking back 5" DP in derrick F/1,003' - T/540' MD, 475gpm= 840psi, F/O= 35%. POOH on elevators racking back 5" DP in derrick F/540' - T/84' MD,
monitoring well on trip tank.
Pump 20bbls fresh water through HES directional BHA. L/D Flex collar, X-O, and UBHO. POOH with BHA per HES DD/MWD. Bit Grade: 1-2-WT-A-E-I-NO-BHA. P/U
Kymera, scribe, RIH t/ 80' MD. HES Upload MWD. Continue P/U BHA #2, RIH T/114'. Latch first std HWDP, RIH, Install FOSV.
While pulling collar slips to M/U BHA, observed row of button dies fall onto rotary with 3 dies falling into wellbore. Inspected and determined Cotter pins were missing
during usage.
Change out dyes in TDS pipe handler. Remove Standoff sheave from derrick for air hoist, free up same, and re-install in derrick. Change out air hoist cable. Visually
inspect TDS and block. Inspect and change out worn tong dies. Inspect all rig floor equipment. Screen up shakers to 120's.
TIH on elevators with 5" HW F/ 114' - T/388' MD. M/U into std, TIH to 475' MD, Circ 500gpm= 750psi, 40rpm= 850ft/lbs TQ. Madd pass F/475' - T/388' MD. Bottom of
conductor observed at 382' MD. Cont TIH F/ 475'- T/941' MD. Wash and Ream F/941' - T/1,003' MD, 500gpm= 969psi, 40rpm= 1,000Ft/lbs TQ.
CBU at 1,003' MD, 500gpm= 969psi, 40rpm= 1,000Ft/lbs TQ. 40% increase in cuttings at BU.
Slide/Drill 12.25" surface section F/1,003' - T/1,125' MD. Total: 122' (AROP: 61FPH), 500gpm= 969psi, 40rpm= 1K ft/lbs TQ, 0-10K WOB, F/O= 35-40%, P/U=100K, S/O=
100K, ROTW=100K. Taking Gyro surveys every 30' after drilling each std until MWD free of interference.
Slide/Drill 12.25" surface section F/1,125' - T/1,505' MD (1,476' TVD), Total: 380' (AROP: 63.3FPH), 500gpm= 1150psi, 40rpm= 1K ft/lbs TQ, 0-10K WOB, F/O= 35-40%,
9.1ppg ECD w/ 8.8ppg MW, P/U=110K, S/O= 100K, ROTW=105K. Taking Gyro surveys every 30' after drilling each std until MWD free of interference. Pump Hi-vis
sweeps every 500'.
Distance to WP01: 56.55', 52.44' Low, 21.16' Right.
Daily Discharge: 276 bbls
Cumulative discharge: 601 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 2.3 lbs
Cumulative metal: 2.3bbls
Report Number
10
Report Start Date
8/11/2024
Report End Date
8/12/2024
Operation
Slide/Drill 12.25" surface section F/1,505' - T/2,062' MD (1,854,' TVD), Total: 557' (AROP: .93FPH), 600gpm= 1550psi, 50rpm= 2-3K ft/lbs TQ, 0-12K WOB, F/O= 45.2%,
9.3ppg ECD w/ 8.8ppg MW, P/U=115K, S/O= 105K, ROTW=110K. Taking Gyro surveys every 30' after drilling each std. MWD obtained 3 consecutive surveys at 1,465',
1,533', and 1,556' MD. R/D E-line and Gyro. Pump 30bbl hi-vis sweep at 1,600' MD. Returned on time w/ 50% increase in cuttings. Take bottom survey.
CBU at 2,062' MD, 600gpm= 1,400psi, 50rpm= 3-4Kft/lbs TQ.
Flow check well for 10 min- static. Pump out of hole F/2,062' - T/1,000' MD with no issues. 600gpm= 1,420psi.
Monitor well on trip tank. Observing 1bph seepage. Replace standpipe bleed off choke. Pull covers on draw works, crease coupling and gear on draw works to Elmago.
Grease draw works, TDS, and all relative eqiument. Clean suction strainers on Mud pumps.
TIH on elevators with 5" DP f/ derrick F/1,000' washing last std down, 600gpm= 1,400psi, 40rpm= 1-2Kft/lbs TQ , F/ 1,971' - T/2,062' MD. Observed 22' fill.
Slide/Drill 12.25" surface section F/2,062' - T/2,533' MD (2,079' TVD), Total: 471' (AROP: .78.5FPH), 564gpm= 1,440psi, 50rpm= 5-6K ft/lbs TQ, 0-10K WOB, F/O=
45.2%, 9.3ppg ECD w/ 9.0ppg MW, Backream each std drilled. P/U=120K, S/O= 95K, ROTW=107K. Pump 30bbl hi-vis sweep at 2,097' MD. Returned on time w/ 30%
increase in cuttings.
Slide/Drill 12.25" surface section F/2,533' - T/2,948' MD (2,263' TVD), Total: 415' (AROP: .69FPH), 676gpm= 1,847psi, 50rpm= 5-6K ft/lbs TQ, 0-10K WOB, F/O= 45.2%,
9.33ppg ECD w/ 9.0ppg MW, Backream each std drilled. P/U=125K, S/O= 95K, ROTW=107K. Pump 30bbl hi-vis sweep at 2,553' MD. Returned on time w/ 15% increase
in cuttings.
Distance to WP01: 65.20', 64.48' Low, 9.66' Right.
Daily Discharge: 345 bbls
Cumulative discharge: 946 bbls
DH losses: 17 bbls
Cumulative DH losses: 17 bbls
Metal: 1.3 lbs
Cumulative metal: 3.6bbls
Report Number
11
Report Start Date
8/12/2024
Report End Date
8/13/2024
Operation
Slide/Drill 12.25" surface section F/2,948' - T/3,098' MD (2,308' TVD), Total: 150' (AROP: .60FPH), 675gpm= 1,850psi, 50rpm= 6-7K ft/lbs TQ, 4-10K WOB, F/O= 45%,
9.3ppg ECD w/ 9.0ppg MW, Backream each std 2x. P/U=125K, S/O= 95K, ROTW=107K
Take on btm survey. CBU at 3,098' MDrotating and recirpcating, 675gpm= 1,850psi, 50rpm= 7Kft/lbs TQ.
Flow check well- static. BROOH F/3,098' - T/2,063' MD. 675gpm= 1,800psi, 50rpm= 7Kft/lbs TQ. ±18bph loss rate while pumping out.
CBU at 2,063' MD rotating and reciprocating, 675gpm= 1,600psi, 40rpm= 3-4Kft/lbs TQ. Pump 50bbls of 50 lbs/bbl LCM at 2,065' MD and spot 10 bbls outside pipe.
169gpm= 200psi.
Monitor well on trip tank. Observed ±3bph losses to wellbore. Conduct rig equipment service. Grease TDS, Block, crown sheaves. Remove and cleansuction and
discharge strainers on Mud pumps. CHange shaker screens to 170's, change scalpers to 20's.
TIH on elevators with 5" DP from derrick F/2,065' - T/3,006' MD washing last std down T/3,098' MD. 550gpm= 1,285psi, 50rpm= 5Kft/lbs TQ. No fill observed.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 4/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Slide/Drill 12.25" surface section F/3,098' - T/3,330' MD (2,428' TVD), Total: 232' (AROP: 77.3FPH), 681gpm= 1,850psi, 50rpm= 5-6K ft/lbs TQ, 4-10K WOB, F/O= 49.3%,
9.3ppg ECD w/ 9.0ppg MW, Backream as needed. P/U=125K, S/O= 95K, ROTW=112K. Pump 30bbl Hi-Vis sweep at 3,150' MD. Back early w/ 50% increase in cuttings.
Slide/Drill 12.25" surface section F/3,330' - T/3,785' MD (2,635' TVD), Total: 455' (AROP: 76FPH), 600gpm= 1,589psi, 50rpm= 9-10K ft/lbs TQ, 4-10K WOB, F/O= 33.8%,
9.4ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=150K, S/O= 95K, ROTW=117K. Pump 30bbl Hi-Vis sweep at 3,657' MD. Back late w/ 25% increase in cuttings.
Slide/Drill 12.25" surface section F/3,785' - T/4,247' MD (2,831' TVD), Total: 462' (AROP: 77 FPH), 600gpm= 1,650psi, 50rpm= 11-12K ft/lbs TQ, 4-5K WOB, F/O= 33.6%,
9.4ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=160K, S/O= 90K, ROTW=120K. Pump 30bbl Hi-Vis sweep at 4,073' MD. Back late w/ 25% increase in cuttings.
Distance to WP01: 69.76', 66.92' Low, 19.7' Right.
Daily Discharge: 338 bbls
Cumulative discharge: 1,284 bbls
DH losses: 38 bbls
Cumulative DH losses: 55 bbls
Metal: 1.0 lbs
Cumulative metal: 4.6bbls
Report Number
12
Report Start Date
8/13/2024
Report End Date
8/14/2024
Operation
Slide/Drill 12.25" surface section F/4246' - T/4505' MD (2938' TVD), Total: 259' (AROP: 86 FPH), 650gpm, 1,950psi, 36.2% flow, 50rpm= 11-12K ft/lbs TQ, 4-10K WOB,
9.4ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=165K, S/O= 90K, ROTW=120K.
Take survey on btm, circ. B/U @4505' rot/reciprocating , 650gpm, 1930psi, 50rpm, 11-12k trq. Monitor well f/5min. w/2.8bph static loss rate.
BROOH f/4505' t/3476', 650gpm, 1800psi, 40rpm, 9-12k trq..
TIH f/3476' t/3946', monitoring displacement on the TT.
M/U top drive and spot 50bbl of 50ppb LCM pill @ 230gpm, 315psi.
POOH on elevators f/3946' t/3476', M/U top drive and BROOH f/3476' t/2065', 650gpm, 1540psi, 50rpm, 4-6k trq.
Circ. hole clean @2065', 650gpm, 1550psi, 50rpm, 4-6k trq, no increase in cuttings at B/U.
Service rig: grease all traveling equipment, repair crown light and re-install same. Perform derrick inspaction, check oils in top drive, draw works, rotary table and swivel.
Simop: clean suction strainers on Mud pumps #1 and #2, while c/o butterfly valve on MP#1 line-found impellar parts in valve, isolate and re-pair charge pump.
TIH f/2065' t/4413', M/U top drive and wash dwn t/4506', 650gpm, 1940psi, 4ft of fill on btm.
Slide/Drill 12.25" surface section F/4505' - T/4692' MD (3001' TVD), Total: 186' (AROP: 53 FPH), 650gpm, 1,995psi, 34% flow, 50rpm= 11-12K ft/lbs TQ, 2-5K WOB,
9.4ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=165K, S/O= 90K, ROTW=120K. Back ream as needed, pumped 30bbl hi-vis sweep @4554', sweep came back
on time w/20% increase in cuttings.
Slide/Drill 12.25" surface section F/4692' - T/5067' MD (3120' TVD), Total: 375' (AROP: 62.5 FPH), 659gpm, 2070psi, 32% flow, 50rpm= 13-14K ft/lbs TQ, 2-5K WOB,
9.3ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=175K, S/O= 90K, ROTW=125K. Back ream as needed, pumped 30bbl hi-vis sweep @4554', sweep came back
on time w/20% increase in cuttings.
Report Number
13
Report Start Date
8/14/2024
Report End Date
8/15/2024
Operation
Slide/Drill 12.25" surface section F/5067' - T/5636' MD (3387' TVD), Total: 569' (AROP: 62 FPH), 650gpm, 2200psi, 30.8% flow, 50rpm= 12-13K ft/lbs TQ, 5-14K WOB,
9.5ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=170K, S/O= 105K, ROTW=130K. Back ream as needed, pumped 30bbl hi-vis sweep @5128', sweep came back
on time w/25% increase in cuttings.
Slide/Drill 12.25" surface section F/5636' - T/5920' MD (3506' TVD), Total: 584' (AROP: 63 FPH), 650gpm, 2135psi, 30.8% flow, 50rpm= 16-17K ft/lbs TQ, 5-14K WOB,
9.5ppg ECD w/ 9.1ppg MW, Backream as needed. P/U=170K, S/O= 105K, ROTW=130K.
Pump 50bbl hi-vis sweep w/walnut @TD 5920'md, 3506'tvd, 650gpm, 2125psi, 50rpm, sweep back 12bbls late w/25% increase in cuttings.
Flow check-static loss rate of 3bph. BROOH f/5920'md t/2397', 655gpm, 1840psi, 65rpm, 4-6k trq. monitoring fill on the short system.
L/D 2 bad jts and P/U working single to stay on even stds.
Cont. BROOH f/2397' t/1151'', 692gpm, 1670psi, 60rpm, 3-4k trq. Hose ruptured on Top drive while m/u in the slips down at the f loor, c/o same. Monitor on TT.
Replace ruptured hose on the top drive. Clean rig floor. Simop-c/o shaker screens. Wash/ream std while finishing clean up.
Cont. BROOH f/1151' t/448', 692gpm, 1670psi, 60rpm, 3-4k trq.
Report Number
14
Report Start Date
8/15/2024
Report End Date
8/16/2024
Operation
Circ. hole clean @448', 700gpm, 1375psi, 60rpm, 6-700ft/lbs trq. Loss rate @3bph.
TIH f/448' t/1030', spot 55bbl LCM pill, plus 10bbls to clear bit.
POOH on elevators f/1030' t/295', monitoring fill on the TT.
Monitor well on the TT, while cleaning residue oil from top drive, bails, service loop and kelly hose.
POOH f/295' t/114', m/u 5ft pup on flex DC and flush BHA w/fresh water.. L/D flex DC and UBHO. Download MWD. L/D Bit and motor, Bit grade: 1-2-CD-1-E-I-FC-TD.
L/D handling tools, bails and elevators.
C/O 4-1/2IF saver sub and replace dies in pipe handler grabber.
P/U Parker casing Volant tool and m/u to top drive. Install casing bails and extensions. Install side door elevators. R/U power tongs, false rotary and slips.
Pre-job on running casing w/all involved. P/U shoe track, m/u w/bakerloc and check floats-good. Install baffel top hat. Drill shoe jt-jt-float jt collar-baffel adaptor jt.
Adjust back stop for casing jts to facilitate latching in the door.
Run 9-5/8" 47# DWC-C casing as per talley f/204' t/1981', filling on the fly and topping off every 5jts.
M/U volant to casing and break circ./reciprocate B/U, staging up pumps t/215gpm, 92psi.
Run 9-5/8" 47# DWC-C casing as per talley f/1981' t/3500', filling on the fly and topping off every 5jts.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 5/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Report Number
15
Report Start Date
8/16/2024
Report End Date
8/17/2024
Operation
Cont. Run 9-5/8" 47# DWC-C casing as per talley f/3500' t/4048', filling on the fly and topping off every 5jts.
M/U volant to casing and circ./reciprocate B/U, staging up pumps t/215gpm, 140psi, 11.5% flow, p/u=270k, s/o=110k.
Cont. Run 9-5/8" 47# DWC-C casing as per talley f/4048' t/4901', filling on the fly and topping off every 5jts. trqing ea. jts t/24k ft/lbs
P/U ES-Cementer, baker lock same and m/u into string as per HES/Parker casing. Check set screws-good. Vault rep. RILDS and test seal t/2000psi-good.
Cont. Run 9-5/8" 47# DWC-C casing as per talley f/4901' t/5850', filling on the fly and topping off every 5jts. trqing ea. jts t/24k ft/lbs. Note: @ 4996' was unable to break
over with p/u wt., max p/u 415k.
P/U Vault hanger w/landing jt and pup, M/U into string and remove handling clamp, clean and inspect seals-good. Drain stack, flush well head and riser w/fresh water.
S/O and land hanger in profile, casing set @5908.87'md / 3506'tvd.
M/U volant to casing and circ./reciprocate B/U, staging up pumps t/215gpm, 192psi. L/D side door elevators and ext. links.
Pre-job for 1st stage cement job. R/D volant and l/d same, p/u HES cement head r/u same on casing stump w/cement hose, secure same, load plugs w/DSM/HES reps
present.
HES pump 5bbl water and test lines t/893-4000psi hi-lo/good. HES mix and pumped 60bbls/10.5ppg spacer @4.3bpm/330psi. Drop plug, mix and pump 342bbls of lead
cement @4.3bpm/380psi. Mix and pump 48bbls of 15.8ppg tail cement. Drop 2nd plug, HES pump 20bbls water. Swap over to rig pumps for displacement: pump 322bbls
w/9.3ppg wbm @4.1bpm/380psi ICP, Pump 65bbls 9.6ppg spacer @5bpm/980psi, Pump 16.25bbls 9.3ppg wbm @ 5bpm/958psi FCP. Bump plug 4.5bbl early, cement to
surface @380bbls displaced. pressure up t/1442psi f/5min. bleed off check floats-good.
CIP @ 0100hrs
Pump @ 1bpm 5.5bbls to 2680psi down casing and shift open the ES-cementer. Circ. mud over board until mud returns cement free and uncontaminated. @ 252gpm,
330psi, 258bbls dumped. (240bbl ann. vol.)
Simop-cleanning mud system surface equipment, shaker pans, ditches, 4" hoses.
Cont. circ. and condition mud, cement came back to surface in to surface equiopment, shut dwn and clean and purge line, ditches and pans of cement. Try to re-establish
circ. after dumping more cement from conductor.
Report Number
16
Report Start Date
8/17/2024
Report End Date
8/18/2024
Operation
Circ./condition mud while staging up pumps t/5bpm, 235psi.
Pre-job w/crews for 2nd stage cement job. HES mix and pump 60bbl/10.5ppg spacer @5bpm/270psi, mix and pump 428bbl/12.0ppg lead cement @5bpm/300psi, shut
dwn and drop closing plug, HES pump 20bbl h2o @4.8bpm/300psi. Switch to rig pump and pump 54bbl/9.3ppg wbm @3bpm/239psi FCP. Tool shifted close @1090psi,
brought pressure up t/1440psi and held f/4min. and released pressure. Tool closed, 54bbls cement returned t/surface.
Blow dwn cement line and head, R/D same. R/U vacuum to suck out 9-5/8" casing landing jt.. Flush overboard hoses and well head w/h2o to clear any solids.
Break and L/D landing jt and pup jt, side door elevators, false rotary, clamp, bails, power tongs and slips.
Install rig-up lines on Top drive, pull master bushing f/rotary. Wash/clean flow box dwn flowline to scalpers. Remove 22"x30" lp riser adaptor. Bleed dwn koomey and
remove koomey hoses f/ diverter system. N/D diverter barrel, knife valve f/mud-X. Simop-cleaning pits, shakers, and scalpers.
Remove bell riser f/top of annular, install lifting plate on same. Remove clamp f/mud-X t/annular. Lift annular, N/D mud-X from under annular and remove from cellar.
Remove annular from cellar. Simop- clean mud pumps suction lines, pits 2 & 3, sand traps and flush thru all surface lines and solid equipment.
Suck out 22" riser, clean and organize cellar/Rig floor of tools, gather bolts, remove scaffold board and extra stairs, rigging. Break out bolts on hi-pressure riser to landing
ring for well head. Hoist riser to the rig floor and l/d same w/crane. Simop-dress mud pump #1 w/6" liners and mud pump #3 w/5-1/2" liners.
Prep- landing ring/hanger for well head as per Vault Rep., install and test same t/5k-good. P/U HP riser and install same.
Report Number
17
Report Start Date
8/18/2024
Report End Date
8/19/2024
Operation
R/U to p/u annular and hang off on BOP trolly winches. Start to keel haul out from under white iron.
Shut dwn to prep all equipment for boat back haul. Including cleaning, greasing and blanking mud-X, diverter line, diverter annular and valve. Break DSA and slip on
adaptor.
Cont. kell hauling 13-3/8" 5m annular from under white iron and transfer to STB trolly. Break bolts on 2ft spool under annular and remove from cellar. Set single-mud x
and dbl gate on riser and m/u same, remove 2nd 2ft spacer spool fron topp of dbl gate. Set 5ft spool on dble gate and m/u same.
Trq bolts all bolts on BOP connections, N/U choke and kill hoses w/target 90's. Install all koomey lines to BOP's.
Pressure up accumulator system and check for leaks-none. Fuction test BOP's from komey and both remote stations-good. Assist Beyond w/rig up of MPD equipment.
Simop-building mud in pits 1 & 2.
P/U trip nipple and install same, Latch up stand and m/u runnin tool for test plug, m/u test plug and set same, rack back std. Cleaning in well bay from n/u.
Simop-cont. building mud in pits 1 & 2.
Report Number
18
Report Start Date
8/19/2024
Report End Date
8/20/2024
Operation
P/U test assy and m/u to top drive, install test lines and manifold. Fill and flush BOP's, choke manifold, kill/choke lines and top drive. Simop-building mud in pits1-2-3.
Perform shell test against annular, cmv's 11-13-14-15-16, kv 17-18, ukv, 5" dart t/250 lo-3000 hi f/5min.. Test leaking by annular, bleed off and increase closing pressure,
re-test-leaking on kill target -90. Bleed dwn and re-tighten connections. Re-test -good. Attempt to test UPR t/3500psi, test bled off, function rams and verified alignment
and koomey pressures. TPR 2-7/8 x 5-1/2 VBR's leaking.
Pul test plug and drain stack, close bling rams and isolate koomey, bleed dwn koomey pressure on stack. Open TPR doors, pull rams and c/o top seals, elements and
door seals. Install rams and m/u doors.
Set test plug, fill stact w/h2o, close TPR's and purge air. Test UPR t/250 lo-3500 hi f/5min., leak on UPR door bonnet on hi test. Bleed off pressure and tighten door,
re-test- leak on door, Pull test plug and drain stack, close bling rams and isolate koomey, bleed dwn koomey pressure on stack. Open TPR door and observe scale under
door seal. Clean and re-seal, close door and tighten door. Open blinds, Set plug and fill stack w/h2o, purge air and re-test t/250-2500 f/5min.-good.
Simop-building mud in pits1-2-3.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
428bbl/12.0ppg lead cement @5bpm/300psi, shutj
dwn and drop closing plug,
mix and pump 342bbls of leadpp p g
cement @4.3bpm/380psi. Mix and pump 48bbls of 15.8ppg tail cement
ppp ppg @
54bbls cement returned t/surface.
Page 6/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Clean and organize scalper area, trip tanks, brake cooling pumps, cellar grn/wht iron. Remove vacuum and h2o hoses from wellhead room. Re-route lo/hi pressure hoses
in front of sub structure and walk ways. Route 4" hose f/blue tank on platform to shakers on rig. Install hyd. lift cylinder on hawk jaw. Clean and organize BOP area in sub
structure.
Open UPR, pull test plug and test assy. to floor and l/d same. Drain BOPE.
Deflate 22" air boot, remove clamp f/trip nipple and pull nipple to rig floor. Install Beyond test plug into RCD head and tighten same.
Test 9-5/8" casing t/250-3500psi f/5min on chart against blind rams. Bleed pressure , open blinds and re-test t/250-1200psi f/5min. f/5min. against RCD head, good test's.
Bleed off and rig dwn RCD test plug. Close blind rams and stow away test lines and equipment. Adjust 30" rotary pan t/polution pan.
Pollution pan dresser sleeve installed upside dwn, while removing to re-install correctly, dresser sleeve dropped before a tugger could be attached approx. 12ft to cellar
green iron, no one was working under or around it at that time-exclusion zone was utilized. Report to follow. Simop-building mud in pits1-2-3.
Build stds with 5"DP off the deck in the mouse hole in the rotary table and racking in the derrick.
R/U to test BOP's, m/u test jt and test assy., set test plug, r/u test pump and manifold. Fill stack w/h2o. Purge air from syst em.
Report Number
19
Report Start Date
8/20/2024
Report End Date
8/21/2024
Operation
Cleaned & organized rig waiting on state man.
Test BOPs as per AOGCC. Tested with 5'' & 4.5 Pipe to 250/3000 psi. All test against Test plug. Gas detection system had 7 FP with RIG Floor & Well head methane
failing on visual and audible. Pits failed audible methane and Shakers we had to replace the sensor for the H2s. We had one FP on choke manifold valve #5. Cycled
and retested good. Blinds rams failed on the High. Changed blind ram elements inspect & clean sealing face on bonnet doors and ram cavities. Re-install blind rams,
Retested blind rams good test.
Rig down and remove portable test pump from floor, rig down test hoses and test manifold.
PJSM - Install 36' rotary pan with boot nipple, Install dresser sleeve ring and tighten same. Hook up safety chains to secure boot nipple. Install trip nipple onto stack,
Nipple above trip tank fill up line, measure and mark nipple & remove to be cut to correct size.
Cut trip nipple to correct height for clearance of trip tank fill up line & reinstall same, Pull test plug, install wear bushing. Clear and clean BOP area of all tools and
equipment used for task.
PJSM - Pick up 24 stands of 5" drillpipe racking back in derrick. All pipe drifted and strapped. Continue building 8.8 ppg LSND mud
Change elevators, move mousehole to mousehole slot. Bring bit & bit breaker, float sub, stabilzer to floor. P/U motor.
Report Number
20
Report Start Date
8/21/2024
Report End Date
8/22/2024
Operation
Make up bit to motor, Pick up MWD/LWD tools to 154'
Plug in to load data to MWD/LWD tools, Communication with tools not responsive with ADR LWD tool, several attempts to solve comm problem unsuccessful. P/U 15' pup
joint, rack BHA with smart tools back in derrick to PWD/ADR, P/U new PWD/ADR RIH to 80'
Pick up remaining LWD tools, CTN collar, TM Collar, Plug in and upload data, M/U to top drive & shallow pulse test 350 gpm, 400 psi. Hold PJSM load Nuke sources,
M/U stabilizer & flex NMDC's. TIH picking up 5" HWDP & Jars from derrick to 741'
TIH F/741' - T/ 931' M/U topdrive wash & ream F/931' - T/1,010' 375 gpm, 740 psi.
Attempt to bring rotary online, alarm sounding in TDS control panel, troubleshoot top drive. Unable to calibrate rpm on topdrive. Found bad proximity switch on rpm
gauge, perform manual count of rpm's, mark rpm rheostat for 40 & 80 rpm. new switch to arrive in AM.
Drill out ESCMTR, F/1,010' - 1,018' with 375 gpm, 740 psi, 40 rpm, 6k bit wt. 1,240 ft/lbs. torque. Work string through area 3 times with no difficulties.
Wash & Ream through cement stringers, F/1,018' - T/ 1,203' with 375 gpm, 740 psi, 20 rpm.
TIH F/1,203' - T/ 2,161' Picking up 5" drillpipe, all pipe drifted and tallied. Monitoring returns via trip tank
Fill pipe and break circulation, Obtain torque and drag reading 400 gpm, 990 psi, 10,20,30 rpm = 4,100, 4,200 & 4,300 ft/lbs. torque. Up wt. 120k. Down wt. 95k. Rot wt.
108k.
TIH F/2,161' - T/3,108' picking up 5" drillpipe. Monitoring returns via trip tank.
Take torque and drag readings at 3,108' 400 gpm 1,030 psi. 10,20,30rpm = stall, 7,300, 7,700 ft/lbs. torque Up wt. 140k. down wt. 95k. rot 110k.
TIH from derrick F/3,108' - T/4,609'
Kick while tripping drill performed.
Report Number
21
Report Start Date
8/22/2024
Report End Date
8/23/2024
Operation
TIH F/4,609' to 5,588' Monitoring returns via trip tank
Tagged cement stringer at 5,588' Wash & Ream F/5,588' - T/5,745' 400 gpm, 1,535 psi, 40 rpm, 14.5K/ torque. 5-10k. bit weight
Circulate and condition mud prior to casing test at 5,745' 40 rpm, 450 gpm, 1,650 psi, torque - 15k.
Flow check well static, Open Kill HCR break circulation, space out & close top pipe rams. Open choke and establish circulation through choke line & choke manifold.
PJSM, test 9-5/8" 47# surface casing to 3,500 psi for 30 minutes. Test good and charted. Bleed off pressure open top pipe rams, rig down from test.
Crew change, new crew arrived, Discuss expectations and review all circulating lines on this wellbore, Go over all line ups prior to drilling out of casing shoe and
upcoming mud displacement.
Drill cement & shoe track F/5,745' -T/5,920' 40 rpm, 410 gpm, 1,300 psi, 17k. torque, 5-8k. bit weight. Up wt. 225k, down wt. 90k. rot wt. 120k.
Drill F/5,920' - 5,940' 40 rpm, 410 gpm, 1,300 psi, 16k. torque, 5k. bit wt. up wt. 225k. down wt. 90k. rot wt. 120k.
Circulate bottoms up 410 gpm, 1,300 psi, 45 rpm, 16k. torque.
Build Hi-Vis spacer, displace to 8.8 ppg 2% KCL WBM, 407 gpm, 1,020 psi, 45 rpm, 15k. torque.
Rig up and perform LOT to 13.7 ppg EMW. 8.8 ppg mud weight 900 psi achieved, 3,506 tvd. pumped 3.7 bbl's. returned 1.8 bbl's.
Sim-Op. Transfer 130 bbl. drill water from coil unit to pit # 1.
Fill sand traps circulate at 460 gpm to ensure shakers could handle drilling flow rate. Take SPR's with pumps 1,2&3.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Test 9-5/8" casing t/250-3500psi f/5min on chart against blind rams
Tested with 5'' & 4.5 Pipe to 250/3000
,p ,p ppp
9-5/8" 47# surface casing to 3,500 psi for 30 minutes. Test good and charted.
Drill F/5,920' - 5,940' 40 rpm
perform LOT to 13.7 ppg EMW. 8.8 ppg mud weight 900 psi achieved
Page 7/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drill F/5,940' - T/ 5,962' per DD, 45 rpm, 450 gpm, 1,200 psi, 14k. torque 2k. bit wt. up wt. 200k. down wt. 100k. rot wt. 130k.
Drill F/5,962' - T/ 6,401 (3,714 TVD) 439' (AROP 73.2') 45 rpm, 500 gpm, 1,480 psi, 14k. torque, 5-8k. bit wt. mud wt. 8.8 ppg 42 vis, 9.78 ECD. 225k. Up wt. 95k. down
wt. 120k. rot wt. Max gas units 400.
Survey at 6,127.83' distance to plan 2.14'
Report Number
22
Report Start Date
8/23/2024
Report End Date
8/24/2024
Operation
Drill F/6,401' - T/ 6,872' (3,925 TVD) 471' (AROP 78.5') 50 rpm, 500 gpm, 1,650 psi, 17k. torque, 5-10k. bit wt. mud wt. 8.8 ppg 42 vis, 9.78 ECD. 225k. Up wt. 95k. down
wt. 127k. rot wt.
Backream full stands prior to connection.
Sweep returned on strokes 50% visible increase in cuttings (sand & coal)
Drill F/6,872' - T/ 6,966' (3,948 TVD) 84' (AROP 84') 50 rpm, 500 gpm, 1,740 psi, 16k. torque, 5-10k. bit wt. mud wt. 8.8 ppg 42 vis, 9.78 ECD. 225k. Up wt. 100k. down
wt. 127k. rot wt.
Backream full stands prior to connection.
Pump 30 bbl. Hi-Vis sweep surface to surface, sweep returned on strokes with 20% visible increase in cuttings (sand & coal) Tak e SPR's # 1 & 2 pumps.
TOOH F/6,966' - T/5,839' with no difficulties. Hole took proper fill.
Kick while tripping drill, 35 second secure well, total time 3 min, 30 sec.
Rig service, lubricate traveling equipment, top drive, drawworks, hawk jaw.
PJSM, take fluid from A-20 well use for beneficial reuse on A-21. flow rate 360 gpm, 700 psi. circulate surface to surface.
Rig up and skid upper section of rig to center better over well center. Disconnect trip nipple and realign due to leak, reconnect trip nipple.
TIH F/5,839' - T/6,966' With no difficulties. proper displacement, M/U top drive and wash last stand to bottom 510 gpm, 1,575 psi, 50 rpm, 14k. torque. No Fill.
Drill F/6,966' - T/ 7,058' (4,004 TVD) 92' (AROP 92') 50 rpm, 510 gpm, 1,560 psi, 14k. torque, 5-10k. bit wt. mud wt. 8.9 ppg 40 vis, 10.04 ECD. 210k. Up wt. 100k. down
wt. 130k. rot wt. Max gas 300 units.
Double Backream full stand prior to connection.
Drill F/7,058' - T/ 7,431' (4,124 TVD) 373' (AROP 62.1') 50 rpm, 520 gpm, 1,890 psi, 17k. torque, 5-10k. bit wt. mud wt. 9.1 ppg 41 vis, 10.04 ECD. 215k. Up wt. 110k.
down wt. 140k. rot wt.
Performed MADD pass 7,145' - 7,183'
Survey at 7,108' Distance to well plan 3.71'
Double Backream full stand prior to connection.
Daily DH loss - 0 bbls.
Total DH loss production section - 0
Total DH losses - 0
Metal 1.0 lb.
Total metal 13.2 lbs.
Report Number
23
Report Start Date
8/24/2024
Report End Date
8/25/2024
Operation
Drill F/7,431' - T/ 7,716' (4,260 TVD) 285' (AROP 47.5') 50 rpm, 520 gpm, 1,850 psi, 16k. torque, 5-10k. bit wt. mud wt. 8.9 ppg 40 vis, 10.04 ECD. 210k. Up wt. 100k.
down wt. 135k. rot wt.
Double Backream full stand prior to connection.
Drill F/7,716' - T/ 7,996' (4,405 TVD) 280' (AROP 46.6') 50 rpm, 500 gpm, 1,700 psi, 17k. torque, 5-10k. bit wt. mud wt. 9.0 ppg 39 vis, 9.97 ECD. 210k. Up wt. 100k.
down wt. 140k. rot wt.
Double Backream full stand prior to connection.
Pump Hi-Vis sweep surface to surface, 500 gpm, 1,700 psi 50 rpm, 19k. torque
Short trip F/7,996' - T/ 6,875' monitor hole fill via trip tank. RIH F/6,875' - T/7,996' with no difficulties. M/U top drive and washed last stand down 500 gpm, 1,660 psi, 50
rpm, 17k. torque.
Drill F/7,996' - T/ 8,044' (4415 TVD) 48' (AROP 96') 50 rpm, 500 gpm, 1,660 psi, 17k. torque, 5k. bit wt. mud wt. 9.0 ppg 41 vis, 9.86 ECD. 210k. Up wt. 100k. down wt.
140k. rot wt.
Backream full stands prior to connection.
Flow increase of 10% picked up spaced out shut down pumps, slight flow noted, shut in top pipe rams open choke check for pressure on casing or drillpipe. Zero pressure
opened well performed 10 minute flow check well static.
Drill F/8,044' - T/ 8,277' (4530 TVD) 233' (AROP 80') 50 rpm, 500 gpm, 1,850 psi, 19k. torque, 5-10k. bit wt. mud wt. 9.0 ppg 41 vis, 9.86 ECD. 240k. Up wt. 100k. down
wt. 140k. rot wt.
double backream full stands prior to connection.
Drill F/8,277' - T/ 8,652' (4,713 TVD) 375' (AROP 62.5') 50 rpm, 500 gpm, 1,935 psi, 19k. torque, 5-10k. bit wt. mud wt. 9.1 ppg 38 vis, 9.98 ECD. 250k. Up wt. 110k.
down wt. 150k. rot wt.
Performed MADD pass 7,991' - 8,023'
Pumped sweep at 8,500' 50% increase visible at shakers sand & coal, back on strokes. Max gas 514 units.
Survey at 8,518' Distance to well plan 2.49' 1.2' high 2.18' left.
Double Backream full stand prior to connection.
Daily DH loss - 0 bbls.
Total DH loss production section - 0
Total DH losses - 0
Metal 1.0 lb.
Total metal 14.2 lbs.
Report Number
24
Report Start Date
8/25/2024
Report End Date
8/26/2024
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Flow increase of 10% picked up spaced out shut down pumps, slight flow noted, shut in top pipe rams open choke check for pressure on casing or drillpipe. Zero pressureppp p
opened well performed 10 minute flow check well static.
Page 8/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drill F/8,652' - T/ 8,933' (4,875 TVD) 281' (AROP 56.2') 50 rpm, 520 gpm, 1,850 psi, 18-25k. torque, 5-10k. bit wt. mud wt. 9.1 ppg 40 vis, 10.13 ECD. 250k. Up wt. 110k.
down wt. 150k. rot wt.
double backream full stands prior to connection.
Rig pump losing pressure, Suction screen paccked off with cuttings, found coal under valves, swap to number 3 pump. Cycle pumps to change MWD mode set by
previous pressure loss. Drilling standpipe pressure equalized for drilling ahead.
Drill F/8,933' - T/ 9,198' (5,055 TVD) 265' (AROP 44.2') 50 rpm, 520 gpm, 1,850 psi, 21-22k. torque, 5-10k. bit wt. mud wt. 9.1 ppg 40 vis, 10.13 ECD. 250k. Up wt. 110k.
down wt. 155k. rot wt.
Sweep pumped at 8,950' returned 8 bbls. late with 40% increase in cutting visible at shakers. Coal & sand.
double backream full stands prior to connection.
Drill F/9,198' - T/ 9,405' (5,204 TVD) 207' (AROP 51.8') 50 rpm, 500 gpm, 2,250 psi, 23k. torque, 8-14k. bit wt. mud wt. 9.2 ppg 40 vis, 9.87 ECD. 300k. Up wt. 110k.
down wt. 160k. rot wt.
Sweep pumped at 9,405' returned on strokes with 40% increase in cutting visible at shakers. Coal & sand.
String hung up while backreaming on connection at 9,324'. Jar up - Hammer down until free. Backream to clean up tight spot, work through area at 9,324' until clean.
Pump Hi-Vis sweep while performing second backream on stand sweep pumped at 9,405' returned on strokes with 40% increase in cuttings visible at shakers
MADD pass F/9,306' - 9,340'
Drill F/9,405' - T/ 9,591' (5,349 TVD) 186' (AROP 74.4') 50 rpm, 500 gpm, 2,2500 psi, 24k. torque, 5-10k. bit wt. mud wt. 9.2 ppg 40 vis, 10.08 ECD. 300k. Up wt. 110k.
down wt. 160k. rot wt.
Performed MADD pass 9,306' - 9,340'
Survey at 9,550' Distance to well plan 14.56' 14.54' high .79 left
Double Backream full stand prior to connection.
Daily DH loss - 0 bbls.
Total DH loss production section - 0
Total DH losses - 0
Metal 1.0 lb.
Total metal 15.2 lbs.
Circulate Hi-Vis sweep surface to surface 500 gpm, 2,200 psi, 50 rpm, Torque 22-25k. Up wt. 300k. down weight 110k. rot wt. 160k.
Take SPR's, Flow check well - Static.
TOOH F/9,591' - 9,030' pulled slick. Hole took good fill. Pulling pipe wet.
Report Number
25
Report Start Date
8/26/2024
Report End Date
8/27/2024
Operation
TOOH F/9,030' to 5,839' with no difficulties, Inside casing shoe at 5,908' Flow check well Static.
Circulate 30 bbl. Hi-Vis sweep surface to surface, 400 gpm, 1,200 psi, 50 rpm. Sweep at surface brought back clay and sand.
Perform FIT to 11.5 ppg EMW 550 psi, 9.2 ppg mud weight good test. Test charted. Pumped 4.8 bbl's. returned 3.6 bbl's after pressure bleed off.
Latch stand from derrick with bad joint and lay down same. Bring WWT/NRP's to floor and position for installation.
Pump 30 bbl. dry job, Clear and clean rig floor.
PJSM on WWT/NRP installation, TIH F/5,839' - T/6,844' Monitor well on trip tank received proper displacement.
TOOH F/6,844' - T/2,919' Installing WWT/NRP's. Installed on 40 stands. Hole took correct fill.
TOOH F/2,919' - T/BHA at 742' HWDP.
Hole took correct fill.
Rack back HWDP & Jars in derrick, Lay down circulating sub, float sub. P/U 1 joint of 5" Drillpipe, Flush BHA with fresh water, Rack back joint of drillpipe & 2 NMDC's.
Pull Nuke sources, Download MWD, Receive and verify all data, wipe tool clear of data, load MWD tools for BHA # 4.
Daily DH loss - 0 bbls.
Total DH loss production section - 0
Total DH losses - 0
Metal 0.0 lb.
Total metal 15.2 lbs.
Report Number
26
Report Start Date
8/27/2024
Report End Date
8/28/2024
Operation
HES download well data from MWD tools. Encountered download issues due to software.
Remove TM collar from assembly. Pull up and inspect bit; one small chipped tooth- Good. M/U and torque TM collar. Upload well data into MWD tools. Shallow test MWD
w/ 400GPM= 700psi.
PJSM. HES load radioactive sources into tools. RIH on NMDC F/ derrick. RIH w/ 5" HWDP F/ derrick to 457' MD.
TIH with 5" HW on elevators F/457' - T/741' MD. TIH with 5" DP on elevators f/ derrick F/ 741' T/ 3,147' MD. Filling pipe every 20 stds. Monitor well on trip tank for proper
displacements.
Circulate and record pressure prior to dropping agitator dart. 400gpm= 954psi, activation of dart: 400gpm= 1,275psi.
TIH with 5" DP f/ derrick on elevators F/3,147' - T/5,773' MD. Filling pipe and breaking circ every 20 stds. Monitor well on trip tank for proper displacements.
Change prox sensor for RPM on top drive. Circ at 400gpm= 1,479psi, rotating 30, 40, and 50 rpms to verify working correctly- good.
Check MWD signal with 400gpm= 1,479psi. Increased to 480gpm= 1875psi. Signal interruption due to agitator.
Slip and cut 82' of drill line. Grease crown, block, and top drive. Functioned C-O-M, Reset same. Calibrate block height and hookload.
TIH w/ 5" on elevators F/ 5,773' - T/7,844' MD. Hole displacing calculated displacement.
Fill pipe and circulate 480gpm= 2,200psi. 40 RPM= 8-10KFt-lbs TQ. HES MWD troubleshoot signal issues.
TIH with 5" DP on elevators F/ 7,844' - T/8,692' MD. Ovserved 50K down wt. P/U, M/U into TDS, wash and ream with 400gpm= 1,800psi, 40rpm= 10Kft-lbs TQ. Circulate
and condition while troubleshoot MWD. Recycle pumps and dend dowlink. MWD recieved pulse. Max gas 620 units.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Perform FIT to 11.5 ppg EMW 550 psi, 9.2 ppg mud weight good test
Page 9/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
TIH F/ 8,692' - T/9,445', Wash and ream F/ 9,445' - T/9,540' MD. Pump 30 bbls Hi-Vis sweep, CBU 1.5 times, 500gpm= 2,600psi, 40rpm= 12Kft-lbs TQ. 20% increase in
flow at cuttings. Sand, clay, and coal.
PJSM, Remove trip nipple in preparation for Installation of RCD bearing.
Daily Discharge: 33 bbls
Cumulative discharge: 1,516 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 3.0bbls
Report Number
27
Report Start Date
8/28/2024
Report End Date
8/29/2024
Operation
Install RCD bearing
Slide/Drill F/9,591' - T/9,724' (5457 TVD) 133' (AROP 53') 50 rpm, 500 gpm, 2800 psi, 12-14k. torque, 8-12k. bit wt. mud wt. 9.2 ppg 38 vis, 10.28 ECD.220k. Up wt.
140k. down wt. 160k. rot wt.
Conducted choke washout drill and failed floats drill with both crews.
Crew one response time 3mins 22 secs.
Crew two response time 3mins 48 secs.
Slide/Drill F/9,724' - T/9982' (5689'TVD) 258' (AROP 43'') 50 rpm, 500 gpm, 2800 psi, 12-14k. torque, 8-12k. bit wt. mud wt. 9.2ppg 40 vis, 10.28 ECD.220k. Up wt. 140k.
down wt. 160k. rot wt.
MADPASS slides on second back ream.
Slide/Drill 8.5" production section F/9,982' - T/10,294' MD (5,947' TVD), Total: 312' (AROP: 48fph), 490gpm= 3,050psi, 50RPM= 15Kft-lbs TQ, 12-14 WOB, 10.4ppg ECD
w/ 9.3ppg MW. Back ream 2x; madd passing slides. Pump sweep at 10,050'- 20% increase cuttings; Sand & coal. P/U= 235K, S/O= 135K, ROTW= 170K.
Pump cavitating issues with MP #2. Isolate and bring pump 1 & 3 online. MWD having issues with communication on tools. Clean suction screens on MP #2. MWD
attempting various parameters and filters on tools and different MP combinations to attempt to clean erratic signal- good signal on pump #2 and #3. Obtain good survey.
Isolate #1 and inspect fluid end- good.
Slide/Drill 8.5" production section F/10,294' - T/10,386' MD (6,033' TVD), Total: 92' (AROP: 46fph), 420gpm= 2,200psi, 50RPM= 15-16Kft-lbs TQ, 12-14 WOB, 10.4ppg
ECD w/ 9.3ppg MW. Back ream2x; madd passing slides. P/U= 250K, S/O= 135K, ROTW= 170K.
Distance to Plan: 29.04', 28.87' High, 3.17' Left.
Daily Discharge: 76 bbls
Cumulative discharge: 2,096 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 1.0 lbs
Cumulative metal: 4.0bbls
Report Number
28
Report Start Date
8/29/2024
Report End Date
8/30/2024
Operation
Slide/Drill 8.5" production section F/10,386' - T/10,762' MD (6,365'' TVD), Total: 376' (AROP: 58fph), 470gpm=3050psi, 50RPM= 20-22Kft-lbs TQ, 12-14 WOB, 10.4ppg
ECD w/ 9.4ppg MW. Back ream 2x. Pump sweep at 10,526'- 13bbls late with 20% increase cuttings; sand & coal. P/U= 250K, S/O= 135K, ROTW= 170K.
Circ while C/O liner on MP#2. Build pump a Hi-vis sweep.
Pump sweep at 10,762'- 32bbls late with 30% increase cuttings; sand, coal, and bigger pieces of coal.
Perform wiper trip F/10,762' T/9,600' MD- No issues. TIH washing last std down to 10,762' MD. No fill observed.
Slide/Drill 8.5" production section F/10,762' - T/10,947' MD (6,531' TVD), Total: 185' (AROP: 62 fph), 485gpm= 3,050psi, 50RPM= 20-21Kft-lbs TQ, 14-15 WOB, 10.4ppg
ECD w/ 9.3ppg MW. Back ream2x; madd passing slides. P/U= 250K, S/O= 140K, ROTW= 170K.
Slide/Drill 8.5" production section F/10,947' - T/11,182' MD (6,759' TVD), Total: 235' (AROP: 39 fph), 456 gpm= 2,523psi, 50RPM= 20-21Kft-lbs TQ, 14-15 WOB, 10.5ppg
ECD w/ 9.5ppg MW. Back ream2x; madd passing slides. P/U= 250K, S/O= 140K, ROTW= 170K.
Distance to Plan: 6.18', 2.68' High, 5.57' Left.
Note: Found 24ft discrepency in pipe tally, correct same prior to TD. MWD will correct surveys and logs after TD.
Daily Discharge: 152 bbls
Cumulative discharge: 2,248 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 2.0 lbs
Cumulative metal: 6.0bbls
Report Number
29
Report Start Date
8/30/2024
Report End Date
8/31/2024
Operation
Slide/Drill 8.5" production section F/11,182' - T/11,209' MD (6,762' TVD), Total: 27' (AROP: 27' fph), 456 gpm= 2,523psi, 50RPM= 20-21Kft-lbs TQ, 14-15 WOB, 10.5ppg
ECD w/ 9.5ppg MW. Back ream2x.. P/U= 250K, S/O= 140K, ROTW= 170K.
Get on BTM survey. CBU 450 gpm = 2500 psi, 50RPM= 22Kft-lbs TQ,
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Conducted choke washout drill and failed floats drill with both crews.
Crew one response time 3mins 22 secs.p
Crew two response time 3mins 48 secs.
Page 10/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Short trip backream F/11,209' T/10,740' 450 gpm = 2500 psi, 50RPM= 22Kft-lbs TQ,
RIH pumping F/10,740' T/11,209', 350gpm = 1400 psi no fill on BTM.
OE and town GEO decided we need to drill ±200' further to get into the Beluga T & U sands.
Slide/Drill 8.5" production section F/11,209' - T/11,394' MD (6,925' TVD), Total: 185' (AROP: 41 fph), 456 gpm= 2,523psi, 50RPM= 20-21Kft-lbs TQ, 14-15 WOB, 10.5ppg
ECD w/ 9.5ppg MW. Back ream2x. P/U= 280K, S/O= 135K, ROTW= 190K.
Get final survey on BTM
Pump marker sweep to gauge hole, sweep came back 62bbls late with 20% increase at the shakers.
Prep pits for weighting up well to 10.1ppg
Wt up mud from 9.6ppg to 10.1ppg. 350gpm= 1,722psi with 10.4ppg ECD. sowed pupms down keeping ECD below 10.8ppg. 250gpm= 1,135psi. 50rpm= 24-27Kft-lbs
TQ.
Flow check well for 10 min- static. Line up to pump across top of hole with MPD, 210gpm= 115psi. POOH on elevators racking back 5" DP in derrick F/11,394' - T/9,546'
MD with 50-100K overpull off slips. Monitor fill on MPD.
Perform flow check- good. R/D drill nipple, Pull RCD bearing per Beyond Rep. Install trip nipple and flood test same- good.
POOH on elevators racking back 5" DP in derrick F/9,546' - T/5,906' MD. Monitor well for proper fill.
Distance to Plan: 21.03', 14.59' Low, 17.83' Left.
Daily Discharge: 294 bbls
Cumulative discharge: 2,542 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
30
Report Start Date
8/31/2024
Report End Date
9/1/2024
Operation
CBU at shoe getting back mostly sand and clay.
Flow checked well 10 min no flow
Pumped Dry job
POOH F/5906' to BHA
Flow checked well 10 min no flow.
LD BHA #4 as per DD / MWD.
Bit grade 1-2-CT-G-X-I-WT-TD
RU to pull wear bushing.
Pull wear bushing.
RU test equip and MU test jts. Test gas alarms, all passed.
Test BOPE on 5" and 4.5” test joint to 250/3,000psi charted for 5/5 Min.
While bleeding off after second test, the bleed back of pressure came off to quick, assuming weep hole clogged. Noticed trapped pressure behind CM valves. Bled off all
lines and open BOPs. Unseat test plug and pull to surface to verify weep hole- Good. Add weep hole sub to testing assembly due to clearance between test plug and
wellhead, RIH and Reseat test plug.
Test BOPE on 5" and 4.5” test joint to 250/3,000psi charted for 5/5 Min. Tested CMV 1-16, (1)- 5" Dart, (2)- 5" TIW, UPR/LWR IBOP, Kill valves 17-18, Kill HCR. Choke
HCR, manual Kill/choke, Super Choke 12-13 and manual on CMV to 1,500psi, Upper (2.875" x 5 ½” VBR) and Lower VBR Rams (5" Fixed), Annular 250/3,000psi. All
testing conducted with H2O. 7 of 11 test completed.
CM valve #8 failed test.
Witness waived by AOGCC Rep Jim Regg.
Daily Discharge: 187 bbls
Cumulative discharge: 2,729 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
31
Report Start Date
9/1/2024
Report End Date
9/2/2024
Operation
Continue test BOPE on 5" and 4.5” test joint to 250/3,000psi charted for 5/5 Min. Tested CMV 1-16, (1)- 5" Dart, (2)- 5" TIW, UPR/LWR IBOP, Kill valves 17-18, Kill HCR.
Choke HCR, manual Kill/choke, Super Choke 12-13 and manual on CMV to 1,500psi, Upper (2.875" x 5 ½” VBR) and Lower VBR Rams (5" Fixed), Annular 250/3,000psi.
All testing conducted with H2O.
C/O CMV # 8 and retest breaks and valve good test.
Witness waived by AOGCC Rep Jim Regg.
RD test equip and test JT. Remove test plug and install wear ring.
Clean and clear rig floor.
MU BHA #5 Geo tap BHA as per DD / MWD T/118' MD. Download MWD tools. Shallow hole test tools, 410gpm= 800psi. Cont. TIH with BHA F/ 118' - T/728' MD.
RIH with Geo-Tap BHA on 5" DP from derrick F/728' - T/10,050' MD, Filling every 20 stds. Monitor trip tank for proper displacements.
Held well control drill: TIW stabbed and closed 38 sec, total drill 3 min 10 sec. All crew members reported in.
CBU at 10,050' MD. 374gpm= 1,329psi. 32rpm= 20Kft-lbs TQ. Max gas= 462
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 11/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
HES DD/MWD Madd Pass for stretch correlation. Orient TF, P/U to station- HES Town support decided to re-log. TIH T/10,211' MD. Madd Pass for stretch correlation.
Orient TF, 492gpm= 2,208psi, 35rpm= 19-20Kft-lbs TQ. POOH to test first depth of 9,845' MD W/492gpm= 2,140psi.
Daily Discharge: 4 bbls
Cumulative discharge: 2,733 bbls
DH losses: 0 bbls
Cumulative DH losses: 0 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
32
Report Start Date
9/2/2024
Report End Date
9/3/2024
Operation
Geo-tap locations 9,845', 9,830', 9,805', 9,798'.
PUH F/9,860' T/ 8,920'
Madd Pass for depth and stretch correlation. Geo tap sample at 8,584'.
POOH on elevators F/8,670' - T/7,791' MD, monitoring well on trip tank.
Madd Pass for depth and stretch correlation. Geo tap sample at 7,570'- no seal, P/U to 7,569', no seal. P/U to 7,563' MD. and obtained seal. P/U and take pressure
samples at 7,500' and 7,370' MD.
ECD spike to 12.6ppg. Flow dropped and pressure spiked to 2,600psi during correlation for next sample point. Observed 10bbl loss. Slack off past sample area, CBU
464gpm= 1,768psi, 50rpm= 16-17Kft-lbs TQ to clean hole at 7,456' MD.
Madd Pass for depth and stretch correlation. Geo tap sample at 7,300', 7,235', 7,100'. Madd pass F/7,085' - T/7,030 MD. P/U to 6,825', 6,725', 6,600', and 6,495' MD and
take pressure sample.
Orientate tool face and take samples at 6,465', 6,420' and 6,380' MD. 474gpm= 1,648psi.
TIH on elevators 5" DP from derrick F/6,469' - T/8,629' MD. Monitor well on trip tank for proper displacements.
Daily Discharge: 122 bbls
Cumulative discharge: 2,855 bbls
DH losses: 10 bbls
Cumulative DH losses: 10 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
33
Report Start Date
9/3/2024
Report End Date
9/4/2024
Operation
RIH on elevators F/8,629' - T/11,270' MD. Set down 40K at the following depths 11,018', 11,033', & 11,104'; was able to work through it on elevators.
Washed and reamed to BTM @ 11,394', observed no fill on BTM.
Pump sweep around and circ well clean 450 GPM = 2,100 PSI, 50 RPM = 21k TQ. Sweep back 55bbls late with 10% increase in cuttings.
10 min flow check static well
POOH on elevators racking back 5" DP F/11,394' - T/6,192' MD. Flow check well- static. Monitor well on trip tank for proper displacements.
CBU at 6,192' MD. 400gpm= 1,285psi. 30rpm= 13-15Kft-lbs TQ. Pump 30 bbl dry job. Drop 2.39" hollow drift on wire.
POOH on elevators racking back 5" DP F/6,192' - T/181' MD.
Held well control trip drill with crew. well secured 37 sec. Total drill- 2 min 48 sec. All crew members reported in.
Pump 20 bbls drill water trhough tools. L/D BHA #5 per HES DD/MWD. MWD download tools. Having issues with connection. Decision made to L/D to obtain download.
Bit Grade: 1-2-CT-G-X-I-WT-BHA
Clean and Clear non essential tools, Hawk Jaws from rig floor. PJSM, Change out SRL from Derrick crown.
Service top drive, crown blocks, draw works, and rotating equipment on rig floor.
R/U 4.5"" csg handling equipment. Install long bails, csg elevators, Pull mouse hole stump,
PJSM. P/U 4.5" GBCD 12.6# production shoe track, check floats- good. RIH T/88' MD, baker locking each shoe track connection. Run 4.5" GBCD 12.6# Production liner
F/88' MD - T/172' MD. Torquing connections to 5,600Ft/lbs. Filling every 5 joints. Filling up every jt on the fly.
Daily Discharge: 13 bbls
Cumulative discharge: 2,868 bbls
DH losses: 0 bbls
Cumulative DH losses: 10 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
34
Report Start Date
9/4/2024
Report End Date
9/5/2024
Operation
Run 4.5" GBCD 12.6# Production liner F/172' MD - T/3,680' MD. Torquing connections to 5,200- 5,600Ft/lbs. Filling every 5 joints. Filling up every jt on the fly. Monitor
displacement on TT.
Run 4.5" GBCD 12.6# Production liner F/3,680' MD - T/5,622' MD. Torquing connections to 5,200- 5,600Ft/lbs. Filling every 5 joints. Filling up every jt on the fly. P/U ZXP
liner hanger per Baker Rep. Fill liner tieback sleeve with Zanplex. M/U first std of 5" DP on ZXP, RIH F/5,622' - T/5,908' MD.
R/D casing tongs and equipment, p/u hawkjaws and install. R/U cement equipment and lines.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 12/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
RIH w/4-1/2 liner on 5"DP f/5665' t/5854', monitoring displacement on the TT.
Circ./cond 1.5X tubing volume @ 5bpm, 250psi, p/u=110k, s/o=85k, rot=95k.
Cont. RIH w/4-1/2 liner on 5"DP f/5854' t/11394', monitoring displacement on the TT. Filling pipe every 20std and breaking circ., wash dwn last std @1bpm/220psi-hitting
tight spots, p/u and increase pump t/2bpm/265psi and wash dwn to tag @11394'. P/U= 240K, S/O= 115K
L/D single, p/u 15" pup and cement head, r/u hose and manifold.
P/U off slips and attempt to work pipe. P/U= 350K, S/O= 100K in attempt to free liner. Liner 6' off bottom. Circulate and condition 10.1ppg mud. 4bpm= 528PSI while
attempt to work pipe.
Hold PJSM with rig crew and Halliburton cement crew. PT Halliburton cement lines T/1000/4230psi - Good. Fill surface lines with 5bbl H2O followed by 50bbls 11ppg
tuned spacer at 4.5BPM, 430 psi. Pump 356bbls (843 sks) 12.0ppg Lead cement at 5BPM (Cement wet: 03:30). Follow with 37bbls (180 sks) 15.3ppg Tail cement at
3BPM. Kick out plug with 10bbls H2O. Swap to rig pumps and displace with 178bbls of 10.1ppg mud at 5bpm. ICP= 380psi, FCP=1,270psi, Slowed to 3bpm last 20bbls,
Bumped float 8bbls early. CIP-06:11hrs. Pressure up to 1,800psi and hold for 2 min. Bled back and check floats- Good.
Report Number
35
Report Start Date
9/5/2024
Report End Date
9/6/2024
Operation
P/U to 220K, Apply 2,450psi, hold for 2 min. Slack off string and pressure up t/3560psi to set packer and release from liner as per Baker Rep.. P/U t/5732' and circ. B/U,
cemnt to surface @102bbls pumped, dump -spacer, cement and contaminated mud.
R/D cement head and equipment, 2 singles and 15' pup. f/5730' t/5685'.
Circ. wiper ball and B/U @ 10bpm, 425gpm, 625psi., dumping contaminated mud.
Drain stack and flush with citric water.
Pump 30bbl slug, POOH f/5685' t/2397', monitoring fill on the TT.
R/U to L/D rental pipe, POOH L/D 5" DP f/2397' t/surface, L/D running tool as epr Baker Rep., monitoring fill on the TT.
P/U polish mill and R/U NRP install tools and crates to rig floor.
RIH w/ polish mill on 5" DP from derrick T/3,804' MD', removing NRP's as per WWT Rep, monitoring displacement on the TT.
R/D NRP equipment and remove crates of NRP's F/ rig floor.
RIH w/ polish mill on 5" DP out of derrick F/3,804' - T/5,679' MD. Monitor well on trip tank for proper displacements.
Break circulation at 3bpm= 258psi. 20 RPM= 9Kft/lbs TQ. S/O per Baker Rep F/5,679' tagging top of liner at 5,736' MD, rotating through cleaning seal bore profile. P/U=
150K, S/O= 100K, ROTW= 120K.
R/U and test liner top to 3,000psi for 10 charted min- good. R/D test equipment. 5.9bbls in, 5.9bbls bled back.
Displace well to 8.6ppg FIW. 439gpm= 948psi, taking returns overboard. Flush through surface equipment with FIW.
POOH with 5" DP F/5,678' t/5301' MD. Monitor well on trip tank for proper displacments.
Daily Discharge: 633 bbls
Cumulative discharge: 3,528 bbls
DH losses: 0 bbls
Cumulative DH losses: 10 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Report Number
36
Report Start Date
9/6/2024
Report End Date
9/7/2024
Operation
Cont. POOH with 5" DP F/5,301' t/4740' MD. Monitor well on trip tank for proper displacments.
POOH sideways, L/D 5"DP f/4740' t/surface, L/D polish mill as per Baker Rep.
Service rig, p/u wash tool and m/u on std, wash wellhead profile, l/d tool and rack std. Clear rig floor. R/U tbg running equipment.
P/U 4.5" seal assembly per Baker Rep. M/U and RIH with all assositated jewelry on 4.5" 12.5# L-80 IBT upper completion T/2,569' MD. RIH with S-Max F/2,569' -
T/2,812'. Torquing to an average of 4,150ft/lbs. Monitor well on trip tank for proper displacements.
RIH with all associated jewelry on 4.5" 12.5# L-80 S-Max F/2,812' - T/2,844' MD. Cont RIH with 4.5" 12.5# L-80 IBT F/2,844' - T/5,282' MD. P/U Baker TE S-5 SSSV;
Pollard Rep terminate line and test to 5,000psi f/ 10min- good. Cont RIH F/5,282' - T/5,688' MD. Monitor well on trip tank for proper displacements.
Report Number
37
Report Start Date
9/7/2024
Report End Date
9/8/2024
Operation
R/U hose and pump in sub. M/U into string,break circulation at .5 bpm= 57psi while s/o, once seals entered the seal bore pressure increased t/72psi, shut dwn pump and
bled same. s/o and land on No-Go @5768', l/d 1jt tbg, space out w/10' and 2' pups.
P/U hanger, connect control line, c/o bad fitting and re-connect control line thru hanger. Pressure up t/5kpsi on line f/5min.-good.
Pull inner bushings and lower hanger thru rotary. P/U landing jts and R/U 2"hp hose to test tbg/IA. Lang hanger 2ft off the No-Go as per tally.
Perform seal test on hanger t/5kpsi f/15min.-good. Turn landing jt 6 turns left, then 4 turns right, P/U 40k on hanger f/1min. to ensure hanger is set in the wellhead-good,
S/O to neutral wt.
Fill 2" hp test hose with water and purge air, attempt to test 4-1/2" 12.6# tbg t/3kpsi, leaking between pump in sub and XO, re-tighten same and re-test, still leaking.
Back hanger running tool out and pull landing joint. Torque 4.5" IF connection between X/O and pump-in sub. Unable to sting into hanger. Pull landing joints and hanger
running tool to rig floor. Remove dogs on hanger running tool per Vault rep. Run back in and sting into hanger.
Test TBG to 3,000psi for 30 charted min- good. Test IA to 3,000psi for 30 charted min while holding 3,000psi on tbg- good.
L/D landing joints and hanger running tool. R/D Parker csg running equipment. Clear rig floor of all non-essential tools. Set BPV in wellhead.
Pull master bushing and clean out flow box. Remove trip nipple, N/D BOPE. SIMOPS: Remove clams for transverse package. Built 8.8ppg LSND
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Test TBG to 3,000psi for 30 charted min- good. Test IA to 3,000psi for 30 charted min while holding 3,000psi on tbg- good
p yp
Pump 356bbls (843 sks) 12.0ppg Lead cement at 5BPM (Cement wet: 03:30). Follow with 37bbls (180 sks) 15.3ppg Tail cement
B/U,,ppy, p, g ppp
cemnt to surface @102bbls pumped, dump -spacer, cement and contaminated mud
Page 13/13
Well Name: NCIU A-21
Report Printed: 2/11/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
N/U 5M tree per Vault Rep. Test void to 5,000psi for 15min- Good. Test Tree and components to 5,000psi for 15 min- Good. Test body to 5,000psi. SIMOPS: Pull V-Door
and assosiated equipment in preparation for skidding.
Daily Discharge: 1,591 bbls
Cumulative discharge: 5,119 bbls
DH losses: 0 bbls
Cumulative DH losses: 10 bbls
Metal: 0.0 lbs
Cumulative metal: 6.0bbls
Field: North Cook Inlet Unit (NCIU)
Sundry #: 224-086
State: ALASKA
Rig/Service: 151
Page 1/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:10/1/2024 End Date:
Report Number
1
Report Start Date
9/28/2024
Report End Date
9/28/2024
Last 24hr Summary
Ops Initiated GL down IA to blow out IA and tubing above liner top. Calculated tubing + IA volume = 375bbls. Recovered ~372bbls total. Ending IAP was 470psi at
1.45MM GL rate. (Psc of dome valve = 750psi).
Report Number
2
Report Start Date
10/1/2024
Report End Date
10/2/2024
Last 24hr Summary
Ops fluid packed tubing for logging with 86bbls (expected fillup was 86bbls). Stab on well, PT(L-250, H-1500). Pressure tested with weight bar. (Passed).
Performed drift run to 5700'.
Report Number
3
Report Start Date
10/3/2024
Report End Date
10/4/2024
Last 24hr Summary
RIG UP AND PT 250L/1500H. RIH AND TAG WITH CBL AT 5,825'.
Report Number
4
Report Start Date
10/7/2024
Report End Date
10/8/2024
Last 24hr Summary
RU Coil tubing on A-21. Fluid pack reel, MU motor and 3.77”OD mill. Pressure test BHA to 3000psi - Test good, Pressure test lubricator and iron to 250psi/3,000psi
- Test good. RIH, tag up on X-nipple at 5,711ft and bump motor to go through. Tag at 5,819' work motor to 5,920ft pumping 1bpm. RIH w/o pumping to 11,151ft,
come online at 1.5BPM and clean out to 11,346' (PBTD). Circulate out 86bbl of mud and 87bbl of drill water. RU AK E-line on top of coil BOPE's, MU CBL tools.
Pressure test lubricator to 250psi/3000psi - Test good. RIH to 11,346', temporarily detained, pressure up well to 900psi with production gas, Pull CBL to liner top.
POOH, secure well.
Report Number
5
Report Start Date
10/8/2024
Report End Date
10/9/2024
Last 24hr Summary
RD E-line, RD Coil tubing. Written approval from AOGCC recieved to authorize perforating as written (based on CBL data)
Report Number
6
Report Start Date
10/9/2024
Report End Date
10/10/2024
Last 24hr Summary
RU Fox coiled tubing (weekly BOP test completed on 10/5/24 on B-01B).
Report Number
7
Report Start Date
10/10/2024
Report End Date
10/11/2024
Last 24hr Summary
PTW/PJSM. GIH with wash nozzle on coil. Tag at 5,634' CTM (appears to be at GLM). Unable to work past. POH. GIH with mill and motor. Tag at 5,630' CTM. Kick
on pump and got through. Continue RIH to 11,000'. Secure coil and SDFN.
Report Number
8
Report Start Date
10/11/2024
Report End Date
10/12/2024
Last 24hr Summary
PTW/PJSM. Displace well to N2 using coil. Recovered 171 bbl water. Pumped a total of 124,244 scf N2. POH with coil and RD. Final WHP 450 psi.
Report Number
9
Report Start Date
10/15/2024
Report End Date
10/16/2024
Last 24hr Summary
PTW/PJSM with Fox Energy. RU and pump 31,892 scf N2 to increase SITP to 1,374 psi. SDFN.
Report Number
10
Report Start Date
10/16/2024
Report End Date
10/17/2024
Last 24hr Summary
PTW/PJSM. AK E-line crew change. P-test to 250/3,000 psi. Perforate Beluga T f/ 11,160' - 11,170', Beluga S f/ 11,056' - 11,062', and Beluga Sa f/ 10,946' - 10,956'
with well shut-in. SDFN.
Report Number
11
Report Start Date
10/17/2024
Report End Date
10/18/2024
Last 24hr Summary
PTW/PJSM. Perforate Beluga Rd f/ 10,918' - 10,928', Beluga Rc f/ 10,884' - 10,890', Beluga Rb f/ 10,844' - 10,850', Beluga Ra f/ 10,825' - 10,835', Beluga Qc f/
10,777' - 10,783', Beluga Qb f/ 10,742' - 0,756', Beluga Qa f/ 10,678' - 10,684', Beluga Pc f/ 10,629' - 10,643' with well shut-in. SDFN.
Report Number
12
Report Start Date
10/18/2024
Report End Date
10/19/2024
Last 24hr Summary
PTW/PJSM. Ran GPT log. Pressure up well to 900 psi with gas. Continue pressuring up to 2,420 psi with nitrogen to push water. SDFN.
Report Number
13
Report Start Date
10/19/2024
Report End Date
10/20/2024
Last 24hr Summary
PTW/PJSM. Ran GPT. Make repairs on N2 unit and pump nitrogen. Final SITP 2,485 psi. RD N2 and eline. SDFN.
Report Number
14
Report Start Date
10/26/2024
Report End Date
10/26/2024
Last 24hr Summary
PTW/PJSM. RU Fox N2 unit, pressure test to 500psi/4,000psi. SITP: 2,150 psi. IA: 966 psi. Pump 170,282 SCF (1,828 gals) N2 and pressure well to 4000 psi.
Shut in and RD Fox.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:224-086Permit to Drill (PTD) #:224-086
Wellbore API/UWI:50883201990000
Page 2/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
15
Report Start Date
10/27/2024
Report End Date
10/27/2024
Last 24hr Summary
PTW/PJSM. RU AK E-line. SITP: 2,435 psi. PT lubricator to 250 psi low / 3,500 psi high. RIH w/ GPT and find fluid level @ 10,627'. RIH w/ 4.5" CIBP and set @
10,670'. Confirm set with tag. Bleed well pressure to 2000 psi and SDFN.
Report Number
16
Report Start Date
10/28/2024
Report End Date
10/28/2024
Last 24hr Summary
PTW/PJSM. RU AK E-line. SITP: 2,023 psi. RIH w/ 2x6' 2 3/4" 6SPF 60DEG perf guns on switch and perforate Bel_Pb (10,602'-10,608') and Bel_P (10,578'-
10,584') sands @ ~1300 psi. Flow test well. RIH w/ GPT and tag CIBP @ 10,670'. Find fluid level @ 10,456'. Jumper HP gas to tubing and push fluid away.
POOH and SDFN.
Report Number
17
Report Start Date
10/29/2024
Report End Date
10/29/2024
Last 24hr Summary
PTW/PJSM. RU AK E-line. SITP: 966 psi. RIH w/ 4.5" CIBP and set @ 10,570'. Confirm set with tag. RIH w/ 6' and 14' x 2 7/8" 6SPF 60DEG perf guns on
switch. Perforate Bel_Ob (10,516'-10,530') and Bel_Oa (10,502'-10,508'). RIH w/ 4' x 2 3/4" 6SPF 60DEG perf guns, perforate Bel_N (10,460'-10,464'). Flow test
well. RIH w/ GPT and find fluid level @ 10,280'. Jumper HP gas to tubing and push fluid away. POOH and SDFN.
Report Number
18
Report Start Date
10/30/2024
Report End Date
10/31/2024
Last 24hr Summary
PTW/PJSM. RU AK E-line. SITP: 1060 psi. RIH w/ 4.5" CIBP. Decision not to set plug, POOH. RIH w/ 20' x 2 7/8" 6SPF 60DEG perf guns and perforate Bel_Mc
(10,424'-10,444'). Flow test well.
Report Number
19
Report Start Date
10/31/2024
Report End Date
11/1/2024
Last 24hr Summary
PTW/PJSM. RU AK E-line. Well flowing 2.8MMSCFD @ 860 psi. RIH w/ GPT and log down/up passes from 10,200'-10,570' (tag). RIH w/ 20' x 2 7/8" 6SPF
60DEG perf guns and re-perforate Bel_Mc (10,424'-10,444'). Flow test well.
Report Number
20
Report Start Date
11/1/2024
Report End Date
11/2/2024
Last 24hr Summary
PTW/PJSM. RD AK E-line. Well flowing 3.1MMSCFD @ 443 psi.
Report Number
21
Report Start Date
11/9/2024
Report End Date
11/10/2024
Last 24hr Summary
Arrive on platform. PTW/PJSM. RU AK E-line. P-test 250/3,000 psi. Perforate Beluga Mb f/ 10,408' - 10,414' and Beluga Ma f/ 10,386' - 10,396' with well flowing.
SDFN.
Report Number
22
Report Start Date
11/10/2024
Report End Date
11/11/2024
Last 24hr Summary
PTW/PJSM. Perforate Beluga Jc f/ 10,173' - 10,179' with well flowing. Guns stuck. Drop Kinley cutter, made cut, POH and recovered cutter. Sand packed on cutter.
Estimate there is 130' - 180' of wire remaining in the well, along with the gun string. SDFN.
Report Number
23
Report Start Date
11/11/2024
Report End Date
11/12/2024
Last 24hr Summary
PTW/PJSM. RU Pollard slickline. P-test 250/3,000 psi. Run lead impression block - no marks on face, some marks on side. Make 3 bailer runs - recover a total of
3.5 gal sand. SDFN.
Report Number
24
Report Start Date
11/12/2024
Report End Date
11/13/2024
Last 24hr Summary
PTW/PJSM. Make 5 bailer runs - recover a total of 5 gal sand. SDFN.
Report Number
25
Report Start Date
11/17/2024
Report End Date
11/17/2024
Last 24hr Summary
Arrived on platform. Walked down area. Decision made to wait to offload boat due to high winds.
Report Number
26
Report Start Date
11/18/2024
Report End Date
11/18/2024
Last 24hr Summary
PTW and PJSM. Offload boat and spot all equipment. Rigged up coil equipment and stabbed pipe. BOPE test 250psi low/3,000 psi high. Witness waived by Jim
Regg. Secure location and SDFN
Report Number
27
Report Start Date
11/19/2024
Report End Date
11/20/2024
Last 24hr Summary
PTW/PJSM. SITP 1865 psi. RU Fox CT. Troubleshoot equipment issues. RU circulating lines. Decision not to RIH today, prep for work tomorrow. SDFN.
Report Number
28
Report Start Date
11/20/2024
Report End Date
11/21/2024
Last 24hr Summary
PTW/PJSM. SITP 1890 psi. RU Fox CT. MU BHA and PT lubricator to 3000 psi - good test. RIH w/ internal wire grab cleanout assembly while filling hole and
bleeding off well pressure. Tag top of fill at @ 9,938' CTM. Wash to 9,942' w/ slow progress. PU w/ 7K lbs overpull off bottom, POOH. OOH- recovered ~25' of
wire. Secure well and SDFN.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:
Page 3/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
29
Report Start Date
11/21/2024
Report End Date
11/22/2024
Last 24hr Summary
PTW/PJSM. SITP 150 psi. RU Fox CT. RIH w/ internal wire grab cleanout assembly and engage fish @ 10,152' and WT to 10,162' while CBU. POOH- recovered
~56' of wire. RIH w/ hydraulic grapple, tag @ 10,160' and hit 1x with jars (20K over). POOH- recovered entire fish and ~40' of wire attached to rope socket. SDFN.
Report Number
30
Report Start Date
11/22/2024
Report End Date
11/23/2024
Last 24hr Summary
PTW/PJSM. SITP 140 psi. RU Fox CT. RIH w/ cleanout assembly, can't pass GLM @ 5,655'. POOH and MU longer cleanout assembly BHA 2.91" max OD x 18'
OAL. RIH and tag fill @ 10,414' and wash to 10,570' (CIBP). Circulate 10 bbl hi-vis sweep to surface, POOH. RIH w/ 3.80" mill, motor, and 3.80" string mill
assembly and drift for casing patch over Beluga Jc sand- tag up in perf area (depth counter not working correctly). Attempt to mill through tight spot, no luck.
POOH w/ BHA. SDFN.
Report Number
31
Report Start Date
11/23/2024
Report End Date
11/24/2024
Last 24hr Summary
PTW/PJSM. SITP 280 psi. RU Fox CT. RIH w/ 3.75" tapered mill and motor. Tag @ 10,170' (pumps off), PU and mill lightly from 10,162'-10,163' (motor stalling).
POOH to inspect- some wear on outer edge of taper. SDFN.
Report Number
32
Report Start Date
11/24/2024
Report End Date
11/25/2024
Last 24hr Summary
PTW/PJSM. SITP 280 psi. RU Pollard Slickline. PT lubricator to 3000 psi - good test. RIH w/ 3.54" LIB and tag @ 10,528' SLM. RIH w/ 3.72" GR and tag @
10,206' SLM. RIH w/ 3.67" GR and tag @ 10,207' SLM. RD Pollard. SDFN.
Report Number
33
Report Start Date
11/25/2024
Report End Date
11/26/2024
Last 24hr Summary
PTW/PJSM. SITP 300 psi. RU Fox CT. RIH w/ 3.75" tapered mill and motor to tag @ 10,170' CTM (pumps off). PU and begin milling lightly @ 10,163', little/no
progress (motor stalling). POOH to inspect- some wear on outer edge of taper. SDFN.
Report Number
34
Report Start Date
11/26/2024
Report End Date
11/27/2024
Last 24hr Summary
PTW/PJSM. SITP 310 psi. RU Fox CT. Test BOPE to 250/3000 psi per AOGCC standards- good test. Witness waived by Jim Regg, AOGCC. Used gas lift to
unload 86 bbls KCL to surface. Hand over to production and attempt to flow well without isolating Bel Jc perfs.
Report Number
35
Report Start Date
11/27/2024
Report End Date
11/28/2024
Last 24hr Summary
PTW/PJSM. SITP 185 psi. RU Fox CT. RIH w/ cleanout assembly (2.91" max OD x 18' OAL) and tag @ 10,460' CTM. PU t/ 10,000' and pump N2 @ 700 scfm to
unload well. 44,170 scf away and N2 pump went down. Bring gas lift online and N2 pumping again when primed. Total 75,300 scf (809 gals) N2 pumped and 53
bbls KCL recovered. Hand well to production to monitor for night.
Report Number
36
Report Start Date
11/28/2024
Report End Date
11/29/2024
Last 24hr Summary
Well flowing 1.7MMCFD @ 75psi with 1.6MMCFD lift gas. RIH w/nozzle and dry tag at 10,442'. (Bottom of Mc sand 10,444'). See 2k drag down and 12k drag up
through Bel Jc sands (10,156-10,184'). POOH and park at 10,000'. Flowing well and monitoring. POOH from 10,000' to surface. Secure well, LD BHA. Rack back
lubricator. RD Fox coil, drain tanks to production. Well flow died off, shut in well for pressure build up. Plan Forward: E-line wellbore evaluation
Report Number
37
Report Start Date
11/29/2024
Report End Date
11/30/2024
Last 24hr Summary
RDMO Fox CT, MIRU E-line, PT lubricator 250/3000psi, RIH w/ GPT, Fluid level observed at 6,875', SITP 830psi,Top open perf 10,173',Tag at 10,384'. Bleed well to
70psi, fluid rose to 3,000ft.
Report Number
38
Report Start Date
11/30/2024
Report End Date
12/1/2024
Last 24hr Summary
RIH t/ 10,290' with 1-11/16"OD 24arm caliper, Power on caliper, several arms stuck closed. Open and close caliper several times with same results. Log from
10,280-10,080' with 8 of 24arms not open. Caliper full of sand, function caliper on surface and all arms came out (2 stuck in but eventually popped open). A lot of
metal shavings stuck to the CCL magnet.
Secure well, RD AK E-line
Report Number
39
Report Start Date
12/5/2024
Report End Date
12/6/2024
Last 24hr Summary
Rig up slickline. P/T to 2500 PSI, good. Attempt to bail. Encounter mud at 1,600', tools have trouble falling, manage to work them to 1,790'
slickline. Did not see a solid bottom. Mud is stuck to the tubing wall. 3.75" gauge ring
gets stuck at 90' pulling out of well. Pumped methanol until tools came free.
Report Number
40
Report Start Date
12/6/2024
Report End Date
12/7/2024
Last 24hr Summary
Run spear to 1,850' slickline, tools falling very slowly, could not tag bottom.
Report Number
41
Report Start Date
12/18/2024
Report End Date
12/19/2024
Last 24hr Summary
PTW and PJSM. Offload the boat and spot coil equipment.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:
Page 4/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
42
Report Start Date
12/26/2024
Report End Date
12/27/2024
Last 24hr Summary
PTW/PJSM. MIRU Fox CT.
Report Number
43
Report Start Date
12/27/2024
Report End Date
12/28/2024
Last 24hr Summary
PTW/PJSM. RU Fox CT. MU CT connector and lubricator, stab on well. Mix 200 bbls 6% KCL. Test BOPE to 250/3000 psi. Fail/Pass on 2 choke manifold
valves. Witness waived by Jim Regg (AOGCC). MU cleanout BHA, stab on well, and SDFN.
Report Number
44
Report Start Date
12/28/2024
Report End Date
12/29/2024
Last 24hr Summary
PTW/PJSM. SITP: 1990 psi. RU Fox CT. RIH w/ cleanout assembly (2.91" max OD x 18' OAL) filling hole w/ 6% KCL and bleeding off gas pressure. Tag @
10,172' CTM. Attempt to wash down @ 2 BPM and losing returns with increased pump pressure, POOH circulating to 7000' with clean and full returns. RIH again,
tag @ 10,174' and unable to wash down. Repeat tags lost 2' of hole. POOH and CBU. Average losses 12 bbl/hr while circulating. LD wash nozzle and MU
mill/motor assembly. SDFN.
Report Number
45
Report Start Date
12/29/2024
Report End Date
12/30/2024
Last 24hr Summary
PTW/PJSM. SITP: 0 psi. RU Fox CT. RIH w/ 3.687" parabolic/string mill and motor assembly. Dry tag @ 10,166' CTM. PU and mill f/ 10,161'-10,167' @ 1.5
BPM averaging ~1ft/hr. Lost progress milling, POOH to inspect mill- left lower part of motor, string mill, and parabolic mill in well. Secure well, SDFN.
Report Number
46
Report Start Date
12/30/2024
Report End Date
12/31/2024
Last 24hr Summary
PTW/PJSM. SITP: 0 psi. RU Fox CT. RIH w/ 3.75" cut-lip overshot fishing assembly. Get parameters @ 10,000' and RIH to tag TOF @ 10,163'. Set down 2X w/
no pressure increase, PU and dragging 3K over coming out, POOH. OOH- no fish recovery. LD tool string, cut 100' of CT, and service injector. Secure well,
SDFN.
Report Number
47
Report Start Date
12/31/2024
Report End Date
1/1/2025
Last 24hr Summary
PTW/PJSM. SITP: 0 psi. PU IH and lubricator. MU CT connector, pull test 35k lbs and PT 3,000 psi. RIH w/ 3.50" short-catch overshot fishing assembly. Get
parameters @ 10,000' and RIH to tag TOF @ 10,163'. Set down 7k lbs, circ pressure increase and broke over, PU and overpull 11K, 2 jar hits and kicked on pump
at .5BPM CT started moving with 5-10K overpull for first 10’, POOH. OOH- no fish recovery. Break off overshot to send it to be redressed. Secure well, SDFN.
Report Number
48
Report Start Date
1/1/2025
Report End Date
1/2/2025
Last 24hr Summary
PTW/PJSM. SITP: 0 psi. RIH w/ 3.50" short-catch overshot (2.813" grapple). Pump 20 bbls of KCL over TOF. Tagged at 10,161' no change in circ pressure. RIH at
different speeds attempting to latch, had overpull of 66K. Weight cell was not reading correctly. Worked pipe and jars, came free at 55K overpull. POOH. No fish
recovered. Stack down lubricator and IH to troubleshoot IH weight cell. Secure well and SDFN.
Report Number
49
Report Start Date
1/2/2025
Report End Date
1/3/2025
Last 24hr Summary
PTW/PSJM. Move coil equipment to make room for SL. Pull BOP's off well and put tree cap back on. CT crew left platform.
Report Number
50
Report Start Date
1/3/2025
Report End Date
1/4/2025
Last 24hr Summary
PTW/PJSM. Rearrange deck and offload N2 pump and three N2 tanks. Rig up BOP's and N2 hardline. P/U IH stab on well. Pressure test hardline and stack 250
psi/4,500psi. Blowdown CT reel. Bullhead N2 down well, no visible breakover. Total N2 pumped: 84k scf. SITP: 4,500 psi. Secure Well and SDFN.
Report Number
51
Report Start Date
1/4/2025
Report End Date
1/5/2025
Last 24hr Summary
PTW/PJSM. SITP 4,310 psi. Maintenance on CT unit. Transfer well returns to production. Rig down empty N2 tanks, BOP's, and suction hoses. Install tree cap.
Bleed down WH for EL to 1,500 psi. Well Secure. CT crew departed platform.
Report Number
52
Report Start Date
1/5/2025
Report End Date
1/6/2025
Last 24hr Summary
PTW/PJSM. Spot E-line equipment and partial rig up. Cut wire and rehead. Op check tools. SDFN.
Report Number
53
Report Start Date
1/6/2025
Report End Date
1/7/2025
Last 24hr Summary
PTW/PJSM. SITP 1,350 psi. Finish rig up of E-Line unit. PT lubricator 250 psi/ 3,000 psi good. Run 1: Gun gamma with 3.64" OD GR, tool lost power. POOH
reconfigure tool string. Run 2: CCL with 3.64" GR, unable to pass 5,315. Run 3: CCL and extra weight bar, unable to pass 5,315' after multiple attempts. POOH.
Secure well. Laydown lubricator and SDFN
Report Number
54
Report Start Date
1/7/2025
Report End Date
1/8/2025
Last 24hr Summary
PTW/PJSM. Rig down E-line and stage equipment on pipe deck. Rig up coil unit. Good BOPE test 250 psi/ 3,000 psi. Witness waived by Jim Regg. Well Secure
and SDFN.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:
Page 5/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
55
Report Start Date
1/8/2025
Report End Date
1/9/2025
Last 24hr Summary
PTW/PJSM. P/U IH make up nozzle BHA. PT lubricator 250 psi/3,000 psi. Tag at 10,138' CTMD, corrected to RKB 10,171'. P/U to 10,130' paint flag. Run 2: Make
up CIBP and Baker 10 setting tool. RIH to flag, pump 7/8" ball and set CIBP, confirmed with tag and 600 psi pressure test. Pump 31 bbl gel sweep follow by N2 at
600 scf/min. Returned 115 bbls of expected 153 bbls. Total N2 pumped 60k scf. POOH. Break down tools, lubricator, set IH down. Secure well and SDFN.
Report Number
56
Report Start Date
1/9/2025
Report End Date
1/10/2025
Last 24hr Summary
PTW/PJSM. Wait on high winds. Rig up IH and make up reverse out BHA. PT lubricator 250 psi/ 3,000 psi. RIH and started pumping N2 down the backside. N2
pump had issues staying primed up, discovered bad boost pump. POOH. Rig down coil unit, arrange deck, spot E-Line equipment.
Report Number
57
Report Start Date
1/10/2025
Report End Date
1/11/2025
Last 24hr Summary
PTW/PJSM. R/U E-Line Unit. M/U GPT and PT 250/3,000 psi. RIH, locate fluid level at 8,900' and tag CIBP at 10,101'. POOH and L/D lubricator. Cut 10' of wire,
rehead, and op check tools. Well secure and SDFN.
Report Number
58
Report Start Date
1/11/2025
Report End Date
1/12/2025
Last 24hr Summary
PTW/PJSM. R/U Fox N2, install new boost pump, and PT lines 250/2,500 psi. Pressure up well to 1,386 psi. R/U E-Line. Had issues with tool power, new cable
sent out to replace and tools op check passed. RIH with 2-7/8" gun. Correlation pass verified by GEO and OE. Perforated Ha sands 9,795' - 9,811'. 16 psi gain after
15 mins. Secure well. SDFN. Turn well over to Ops for flow testing.
Report Number
59
Report Start Date
1/12/2025
Report End Date
1/13/2025
Last 24hr Summary
PTW/PJSM. R/U N2 and PT line 250/4,000 psi. Online with N2 down well, saw breakover at 2,100 psi. Continued pumping to 2,500 psi. Shutdown N2 and R/U E-
Line. RIH with 1-11/16" GPT to 9,760', no fluid observed. POOH. Secure well and SDFN.
Report Number
60
Report Start Date
1/13/2025
Report End Date
1/14/2025
Last 24hr Summary
PTW/PJSM. SITP: 1,850 psi. R/U E-line and RIH with 4.5" CIBP. Pump N2 to increase tubing pressure to 2,210 psi. Set CIBP at 9,775'. RIH with 2-7/8" guns.
Correlation pass verified by OE and GEO. WHP: 86 psi. Perforate Eb sands 9,432'-9,452'. 16 psi gain in 15 mins. POOH. Tool string covered in mud. Well secure
and SDFN.
Report Number
61
Report Start Date
1/14/2025
Report End Date
1/15/2025
Last 24hr Summary
PTW/PJSM. SITP 110 psi. RU AK E-line. RIH w/ 10' x 2 7/8" 6SPF 60deg guns and set down @ 9,290'. Work multiple times and made it to 9,368' and lost
progress. Pressure up tubing to ~700 psi w/ HP gas and made it to 9,400' w/ no issues. Perforate BEL_Ea (9,390’–9,400’). RIH w/ 17' x 2 7/8" 6SPF 60deg guns,
bleed well pressure, and perforate BEL_Df (9,350’ – 9,367'). POOH, secure well, and SDFN.
Report Number
62
Report Start Date
1/15/2025
Report End Date
1/16/2025
Last 24hr Summary
PTW/PJSM. SITP 285 psi. RU AK E-line. RIH w/ 20' x 2 7/8" 6SPF 60deg guns, perf BEL_De (9,319’ – 9,339') and BEL_Dd (9,263’ – 9,283') in 2 runs. RIH w/
GPT and find fluid level @ 7,160' and tag @ 9,418'. PU to 6000' and make passes while bleeding well to header pressure. Log flowing GPT pass with last fluid
level @ 6,900'. Shut in, POOH, and SDFN.
Report Number
63
Report Start Date
1/16/2025
Report End Date
1/17/2025
Last 24hr Summary
PTW/PJSM. SITP 58 psi. RU AK E-line. RIH w/ GPT and jumper HP gas to tubing. Find fluid level @ 6,330' and tag @ 9,372'. RU Fox N2 and pressure up
tubing from 845 to 2650 psi and broke over. Pumped 81,030 scf (870 gal) N2. Confirmed fluid pushed away w/ GPT and tag @ 9,386'. POOH w/ GPT and RIH w/
CIBP. Set CIBP @ 9,380' and confirm set w/ tag. POOH, secure well, and flow test.
Report Number
64
Report Start Date
1/17/2025
Report End Date
1/18/2025
Last 24hr Summary
PTW/PJSM. SITP 90 psi. RU AK E-line. RIH w/ GPT and find fluid level @ 9,030' and tag @ 9,316'. Bring well online and log flowing GPT pass. Shut in and
jumper HP gas to tubing and monitor fluid level w/ GPT. RU Fox N2 and pressure up well from 930 psi to 2,140 psi and broke over. Pumped 63,000 scf (677 gal)
N2. Confirmed fluid pushed away w/ GPT @ 9,280'. POOH w/ GPT and RIH w/ CIBP. Set CIBP @ 9,250' and confirm set w/ tag. POOH and bleed N2 off well.
SDFN.
Report Number
65
Report Start Date
1/18/2025
Report End Date
1/19/2025
Last 24hr Summary
PTW/PJSM. SITP 250 psi N2. RU AK E-line. RIH w/ 5' x 9' blank x 6' 2 7/8" 6SPF 60deg guns, bleed off N2 to 75 psi, and tag CIBP @ 9,250'. Perf BEL_Dc
(9,233’ – 9,238') and BEL_Db (9,218’ – 9,224'). RIH w/ 10' x 10' 2 7/8" 6SPF 60deg guns on switch and tag @ 9,233'. Issue verifying switches on tool- POOH.
Repair bad connection on roller bogie. RIH w/ 10' x 10' 2 7/8" 6SPF 60deg guns on switch and perf BEL_Da (9,200’ – 9,210') and BEL_Cc (9,103’ – 9,113'). RIH
w/ 10' x 10' 2 7/8" 6SPF 60deg guns on switch and perf BEL_Cb (9,084’ – 9,094') and BEL_Ca (9,064’ – 9,074'). Flow well, SDFN.
Report Number
66
Report Start Date
1/19/2025
Report End Date
1/20/2025
Last 24hr Summary
PTW/PJSM. SITP 20 psi. RU AK E-line. RIH w/ GPT and find fluid level @ 9,086' and tag @ 9,210'. RIH w/ 6' x 4' 2 7/8" 6SPF 60deg guns on switch, pressure
up well to 75psi, and perf BEL_Bf (9,022’ – 9,028') and BEL_Be (9,000’ – 9,004'). RIH w/ 11' x 2 7/8" 6SPF 60deg gun and perf BEL_Bd (8,954’ – 8,965'). Flow
well, SDFN.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:
Page 6/6
Well Name: NCIU A-21
Report Printed: 2/10/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
67
Report Start Date
1/20/2025
Report End Date
1/21/2025
Last 24hr Summary
PTW/PJSM. SITP 56 psi. RU AK E-line. RIH w/ GPT and tag @ 8,941'- no fluid present. Pressure up tubing w/ HP gas to 975 psi and monitor tag depth- last tag
@ 9,189'. POOH w/ GPT. RIH w/ 16' x 2 7/8" 6SPF 60deg gun, bleed well pressure and tag @ 9,189'. Perf BEL_Bb (8,856’ – 8,872'). RIH w/ 14' x 2 7/8" 6SPF
60deg gun and perf BEL_Ba (8,833’ – 8,847'). Flow well, SDFN.
Report Number
68
Report Start Date
1/21/2025
Report End Date
1/22/2025
Last 24hr Summary
PTW/PJSM. SITP 90 psi. RU AK E-line. RIH w/ GPT and find fluid @ 8,670' and tag @ 9,137'. Log flowing GPT pass and POOH. RIH w/ 20' x 2 7/8" 6SPF
60deg gun and perf BEL_Aa (8,642’ – 8,662'). RIH w/ 8' x 2 7/8" 6SPF 60deg gun and perf BEL_Aa (8,634’ – 8,642'). Flow well, RDMO AK E-line.
Field: North Cook Inlet Unit (NCIU)
Sundry #: 324-528
State: ALASKA
Rig/Service:
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Page 1/1
Well Name: NCIU A-21
Report Printed: 2/11/2025
WellViewAdmin@hilcorp.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
5,920.00 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:
Surface Run Date:
8/15/2024 Set Depth (ftKB):
5,908.87
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf): Block Weight (1000lbf):
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
25.00 Ft/Min (ft/min):
3.94
Run Job: Set Depth (ftKB):
5,908.87 Set Depth (TVD) (ftKB):
3,501.4
Centralizer Detail:
134 total
Attribute Subtype: Value:
Pipe Reciprocated?:
No 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)
1RKB 95/8 56.41 56.41 0.00
1 Casing Hanger 9 5/8 8.68 L-80 acme lft hand Cactus 1.00 57.41 56.41
23 23 jt. 9-5/8"casing 9 5/8 8.68 47.00 L-80 CWC-C 943.11 1,000.52 57.41
1 Casing Pup Joint 9 5/8 8.68 47.00 L-80 CWC-C 8.01 1,008.53 1,000.52
1 Stage Collar-ES Cementer II 9 5/8 8.68 47.00 L-80 CWC-C HALLIBURTON 3.70 1,012.23 1,008.53
1 Casing Pup Joint 9 5/8 8.68 47.00 L-80 CWC-C 8.01 1,020.24 1,012.23
116 116 jt. 9-5/8"casing 9 5/8 8.68 47.00 L-80 CWC-C 4,765.85 5,786.09 1,020.24
1 Baffel Adapter 9 5/8 8.68 47.00 L-80 CWC-C HALLIBURTON 1.40 5,787.49 5,786.09
1 1 jt. 9-5/8"casing 9 5/8 8.68 47.00 L-80 CWC-C 38.34 5,825.83 5,787.49
1 Float collar 9 5/8 8.68 47.00 L-80 BTC 1.59 5,827.42 5,825.83
2 2 jt. 9-5/8"casing 9 5/8 8.68 47.00 L-80 CWC-C 78.99 5,906.41 5,827.42
Shoe 9 5/8 8.68 47.00 L-80 BTC NewLand
Oiltools Inc.
2.46 5,908.87 5,906.41
Page 1/1
Well Name: NCIU A-21
Report Printed: 2/11/2025
WellViewAdmin@hilcorp.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 5,908.87ftKB
Wellbore
Original Hole
Job
241-00121 NCIU A-21 Drilling, Drilling -
Drilling, 8/2/2024 06:00
Cementing Start Date
8/16/2024
Cementing End Date
8/17/2024
Top Depth (ftKB)
56.4
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
1,008.0
Bottom Depth (ftKB)
5,920.0
Top Measurement Method
Returns to Surface
Pump Start Date
8/16/2024
Cement in Place At
8/17/2024
Final Circulating Pressure (psi)
943.0
Plug Bump Pressure (psi)
958.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
41.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
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 10.50 60.0 60.0 5 HES
Lead Slurry Lead 802 2.39 12.00 339.0 339.0 5 HES
Tail Slurry Tail 113 2.36 15.61 48.0 48.0 2 HES
Post Flush (Spacer) H2O 8.34 20.0 20.0 4 HES
Displacement MUD 9.60 322.0 322.0 5 Rig
Preflush (Spacer) Spacer 9.60 65.0 65.0 4 RIG
Displacement Mud 9.60 12.0 12.0 2 Rig
Stage Number: 2
Description
Surface Casing Cement
Top Depth (ftKB)
56.4
Bottom Depth (ftKB)
1,008.0
Top Measurement Method
Returns to Surface
Pump Start Date
8/17/2024
Cement in Place At
8/17/2024
Final Circulating Pressure (psi)
244.0
Plug Bump Pressure (psi)
962.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
54.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
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 10.50 60.0 60.0 5 HES
Lead Slurry Lead 987 2.43 12.00 428.0 428.0 5 HES
Post Flush (Spacer) Spacer 8.34 20.0 20.0 5 HES
Displacement Mud 9.30 54.0 53.0 5 Rig
Post Job Calculations
Subtype Value
Page 1/1
Well Name: NCIU A-21
Report Printed: 2/11/2025
WellViewAdmin@hilcorp.com
Casing
ProdSction
Welluore
Welluore Name:
Original Hole f otal bepth oTWelluore DTt( KB:5,920.00 ) riginal ( K/Rf OleEation DTtB:
R( K to v GDTtB: ( K-Casing Llange bistance DTtB: ( K-f Suing Fanger bistance DTtB:
PKf bs
bepthDTt( KB:
Casing
Casing bescription:
Production RSn bate:
9/4/2024 Het bepth DTt( KB:11,391.00
Casing Weight on Hlips D1000luTB:PickUpWeightD1000luTB: Klock Weight D1000luTB:
Make-Up Contractor:
Parker Casing NSmuer Frs to RSn DhrB:18.50 Lt/Min DTt/minB:10.26
RSn Jou: Het bepth DTt( KB:11,391.00 Het bepth DfVbBDTt( KB:6,922.9
Centralizer betail:
AttriuSte HSutype: ValSe:
Pipe Reciprocated?:
No Pipe Rotated?:
No Lloat Lailed?:
No
f est HSutype: PressSre DpsiB:
Casing D) r GinerBbetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner top 7 0.00 5,736.76 5,736.76
7" x 9-5/8" SLZXP w/ DG slips 7 6.28 26.00 L-80 JFE-Lion 21.34 5,758.10 5,736.76
7" XO x 5.5 17# TXP 7 26.00 L-80 JFE-Lion 1.17 5,759.27 5,758.10
10 foot SBE 4 1/2 3.96 17.00 L-80 JFE-Lion 9.65 5,768.92 5,759.27
XO 4 1/2 3.96 17.00 L-80 JFE-Lion 1.20 5,770.12 5,768.92
Liner Joints 4 1/2 JFE-Lion 585.00 6,355.12 5,770.12
Pup Jt 4 1/2 JFE-Lion 9.97 6,365.09 6,355.12
Liner Joints 4 1/2 3.96 12.60 L-80 JFE-Lion 1,002.61 7,367.70 6,365.09
Pup Jt 4 1/2 3.96 L-80 JFE-Lion 9.94 7,377.64 7,367.70
23 Liner joints 4 1/2 3.96 12.60 L-80 JFE-Lion 1,038.09 8,415.73 7,377.64
PUP Jt 4 1/2 3.96 L-80 JFE-Lion 9.67 8,425.40 8,415.73
1 Liner joints 4 1/2 3.96 12.60 L-80 JFE-Lion 958.48 9,383.88 8,425.40
1 RA Tag 4 1/2 3.96 12.60 L-80 JFE-Lion 41.43 9,425.31 9,383.88
1 Liner joint 4 1/2 3.96 12.60 L-80 JFE-Lion 961.35 10,386.66 9,425.31
1 RA Tag 4 1/2 3.96 12.60 L-80 JFE-Lion 41.98 10,428.64 10,386.66
26 Liner joints 4 1/2 3.96 12.60 L-80 JFE-Lion 832.04 11,260.68 10,428.64
1 Liner Joint 4 1/2 3.96 12.60 L-80 JFE-Lion 42.05 11,302.73 11,260.68
1 Baffle Adapter 4 1/2 3.96 12.60 L-80 JFE-Lion 1.11 11,303.84 11,302.73
1 Liner Joint 4 1/2 3.96 12.60 L-80 JFE-Lion 42.06 11,345.90 11,303.84
1 Float Collar 4 1/2 3.96 12.60 L-80 JFE-Lion 1.30 11,347.20 11,345.90
1 Liner joint 4 1/2 3.96 12.60 L-80 JFE-Lion 42.02 11,389.22 11,347.20
1 Shoe 4 1/2 3.96 12.60 L-80 JFE-Lion 1.78 11,391.00 11,389.22
Page 1/1
Well Name: NCIU A-21
Report Printed: 2/11/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Production, 11,391.00ftKB
Wellbore
Original Hole
Job
241-00121 NCIU A-21 Drilling, Drilling -
Drilling, 8/2/2024 06:00
Cementing Start Date
9/5/2024
Cementing End Date
9/5/2024
Top Depth (ftKB)
5,739.0
Cement Stages
Stage Number: 1
Description
Production liner Cement,
Top Depth (ftKB)
5,739.0
Bottom Depth (ftKB)
11,394.0
Top Measurement Method
Volume Calculations
Pump Start Date
9/5/2024
Cement in Place At
9/5/2024
Final Circulating Pressure (psi)
1,270.0
Plug Bump Pressure (psi)
1,270.0
Full Return?
No
Returns During Job (%)
100
Volume to Surface (bbl) Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
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 3.36 11.00 50.0 50.0 5 CMT unit
Lead Slurry Lead 843 2.39 12.00 359.0 359.0 5 CMT unit
Tail Slurry Tail 180 1.24 15.30 40.0 40.0 2 CMT unit
Displacement Mud 10.20 178.0 178.0 5 MP-1
Post Job Calculations
Subtype Value
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: 2/20/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250220
Well API #PTD #Log Date Log Company Log Type AOGCC
ESet #
BCU 18RD 50133205840100 222033 1/27/2025 AK E-LINE Patch
BRU 223-24 50283201830000 221072 1/26/2025 AK E-LINE Perf
CLU 10RD 50133205530100 222113 11/2/2024 YELLOWJACKET PLUG
GP 03-87 50733204370000 166052 12/16/2024 AK E-LINE Plug/Cement
IRU 44-36 50283200890000 193022 1/22/2025 AK E-LINE Perf
KU WD-01 50133203450000 181107 10/15/2024 YELLOWJACKET PERF
MPI 1-29 50029216690000 186181 1/29/2025 AK E-LINE Perf
MPU C-39 50029228490000 197248 1/27/2025 AK E-LINE TubingCut
MPU E-20A 50029225610100 204054 2/1/2025 READ CaliperSurvey
MPU K-33 50029227290000 196202 2/8/2025 AK E-LINE TubeCut
MPU S-08 50029231680000 203123 2/6/2025 AK E-LINE CmtRtr/Punch
MRU A-13 50733200770000 168002 2/6/2025 AK E-LINE TubingPunch
MRU M-02 50733203890000 187061 1/22/2025 AK E-LINE Perf
MRU M-32RD2 50733204620200 217091 2/10/2025 AK E-LINE TubingPunch
NCIU A-09 50883200290100 222024 1/31/2025 AK E-LINE Perf
NCIU A-16 50883201270000 208098 1/30/2025 AK E-LINE Perf
NCIU A-21 50883201990000 224086 1/15/2025 AK E-LINE Plug, Perf
NK-41A 50029227780100 197158 1/6/2025 HALLIBURTON Coilflag
PAVE 3-1 50029238060000 224140 1/4/2025 YELLOWJACKET CBL
PBU P1-13 50029223720000 193074 12/3/2024 HALLIBURTON PPROF
PTM P1-07A 50029219960100 204037 12/31/2024 YELLOWJACKET PPROF
Please include current contact information if different from above.
T40127
T40128
T40129
T40130
T40131
T40132
T40133
T40134
T40135
T40136
T40137
T40138
T40139
T40140
T40141
T40142
T40143
T40144
T40145
T40146
T40147
NCIU A-21 50883201990000 224086 1/15/2025 AK E-LINE Plug, Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.20 14:09:18 -09'00'
1
Gluyas, Gavin R (OGC)
From:Eric Dickerman <Eric.Dickerman@hilcorp.com>
Sent:Tuesday, February 18, 2025 4:18 PM
To:McLellan, Bryan J (OGC)
Cc:Regg, James B (OGC)
Subject:RE: [EXTERNAL] NCIU A-21 (PTD 224-086) witness of cement plug tag
Attachments:NCIU A-21,CIBP AND TOC TAG, 18-FEB-25 PLOT JOB.pdf
Bryan,
Please see the aƩached GR/CCL log of the cement tag on NCIU A-21. As discussed we will be standing by for approval to
perforate.
We tagged twice at 100 fpm with a 460# toolstring. Same depth both tags.
Set bridge plug at 8,630’
Dumped bailed 16 gallons of cement
Tag depth 8,599’
Thank you,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, February 18, 2025 11:41 AM
To: Eric Dickerman <Eric.Dickerman@hilcorp.com>
Cc: jim.regg <jim.regg@alaska.gov>
Subject: [EXTERNAL] NCIU A-21 (PTD 224-086) witness of cement plug tag
Eric,
Hilcorp has approval to run a GR/CCL log to correlate the cement plug tag depth in lieu of a state witness. Please
send in the log within 48 hrs after attaining it.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
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.
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2
+1 (907) 250-9193
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
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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,
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the recipient should carry out such virus and other checks as it considers appropriate.
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: 2/16/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250216
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset #
BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf
CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL
CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL
IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf
KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL
KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL
KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL
KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL
MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF
NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf
PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT
PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT
PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT
PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN
PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT
PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL
PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT
Revision Explanation: Annotations added to processed log.
Please include current contact information if different from above.
162-037 T40080
T40081
T40082
T40082
T40083
T40084
T40085
T40086
T40087
T40088
T40089
T40090
T40091
T40092
T40093
T40094
T40095
T40096
T40097
NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.18 13:06:47 -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:
Date: 2/8/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240208
Well API #PTD #Log Date Log
Company Log Type
BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF
BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT
BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL
BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL
END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24
HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF
KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL
NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey
PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF
PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM
PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM
PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM
PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN
PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM
PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM
SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF
Revision Explanation: Annotations added to processed log.
Please include current contact information if different from above.
T40053
T40053
T40054
T40055
T40056
T40057
T40058
T40059
T40060
T40061
T40062
T40063
T40064
T40065
T40066
T40067
NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.07 13:25:23 -09'00'
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):
11,394 10,163
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
2/14/2025
4-1/2"
LTP & Baker TE-5 5,758 (MD) 3,437 (TVD) & 446 (MD) 446 (TVD)
Perforation Depth MD (ft):
8,634 - 9,238
5,655'
4,705 - 5,082
6,923'4-1/2" 11,391'
30"
9-5/8"
384'
5,909'
MD
1,630psi
6,870psi
384'
3,501'
384'
5,909'
Length Size
Proposed Pools:
L-80
TVD Burst
5,766
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
224-086
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-00-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21
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
6,925 9,250 5,090 1,223psi See schematic
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
By Grace Christianson at 3:03 pm, Jan 31, 2025
325-053
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.01.31 14:49:40 -
09'00'
Dan Marlowe
(1267)
Contingency CT BOP test to 3000 psi.
Dump bail 25' of cement on plug at 6250' md before perforating shallower than 4500' TVD.
Tag TOC and Provide 48 hrs notice for AOGCC opportunity to witness cement tag.
10-404
BJM 2/10/25 DSR-1/31/25
X
SFD 2/10/2025*&:
2/11/2025Jessie L.
Chmielowski
Digitally signed by Jessie L. Chmielowski
Date: 2025.02.11 14:35:59 -09'00'
RBDMS JSB 021325
Perforate Sterling Sands
Well: NCIU (Tyonek) A-21
Well Name:NCIU (Tyonek) A-21 API Number:50-883-20199-00-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-086
First Call Engineer:Eric Dickerman 307-250-4013
Second Call Engineer:Casey Morse 907-777-8322
Maximum Expected BHP:1,613 psi at 3,906’ tvd RFT data from openhole logs
Max. Potential Surface Pressure:1,223 psi Using 0.1 psi/ft gradient to surface
Brief Well Summary:
Jackup Rig #151 drilled and completed Tyonek well A-21 on 9/8/24. The lower Beluga sands were initially
targeted with moderate success, however damaged production liner was encountered at 10,166’ and a coiled
tubing milling BHA was left in hole attempting to clean up the damage liner. The well was subsequently plugged
back and the remaining upper Beluga intervals were perforated and tested without sustained success.
Objective:
Perforate Sterling Sand interval ± 5,945’ to ± 8,600’ (± 3,551’ - ± 4,695’ tvd). All planned perforations are within
the Tertiary System Gas Pool as defined by CO 68A.
Notes on Wellbore Condition:
- Beluga Aa – Dc perforations are currently open, 4,702’ - 5,082’ tvd. The well will build tubing pressure
to 550 psi but will not sustain flow, and no fluid level is logged. It is proposed to leave these
perforations open in case they clean up.
- TRSSSV installed.
- Live gas lift valves are installed.
- 9/7/24
o CMIT-TxIA to 3,000 psi PASSED
o MIT-T to 3,000 psi PASSED (also confirmed liner integrity. No TTP was set).
Perforate Sterling Sands
Well: NCIU (Tyonek) A-21
Eline Perforating Procedure:
1. MIRU Eline and pressure control equipment.
2. Pressure test PCE to 250 psi low / 3,000 psi high.
3. RIH and perforate Sterling sands from ± 5,945’ - ± 8,600’ md (± 3,551’ - ± 4,695’ tvd) per RE/Geo.
a. All proposed perfs within Tertiary System Gas Pool.
b. Top pool is at top Sterling sands: 5,485’ md / 3,329’ tvd.
c. Bottom pool is below PBTD.
d. Pressures:
i. RFT data for the Sterling interval measured a maximum of 1,613 psi formation
pressure.
4. RDMO Eline.
CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and pressure test lines to 3,000psi (or higher if needed).
2. Pressure up on tubing and displace water back into formation.
3. MIRU Eline and pressure control equipment.
4. Pressure test lubricator to 250psi low / 3,000psi high.
5. Set 4-1/2” isolation plug or patch per OE.
6. RDMO Nitrogen and Eline.
CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out)
1. MIRU Coiled Tubing and pressure control equipment.
2. Pressure test lubricator to 250psi low / 3,000psi high.
3. MU FCO BHA.
4. RIH and cleanout to PBTD or as deep as practical.
a. Working fluid will be water, typically 6% KCl (8.33 ppg or greater).
b. Take returns to surface up the CT x tubing annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
d. Utilize gas lift to assist with hole cleaning.
5. Once cleanout is completed, blow well down with nitrogen.
6. RDMO CT.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing (Fox energy)
4. Nitrogen procedure
Test BOP to 3000 psi. -bjm
Dump bail 25' of cement on plug at 6250' md before opening up
perfs shallower than 4500' TVD. -bjm
_____________________________________________________________________________________
Updated By: JLL 01/23/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
6
9
10
11
8
7
1
2
3/4/5
Bel T
Bel Q
Bel S
Bel R
Bel P
Bel N
Bel O
Bel M
Bel J
Bel H
Bel E
Bel D
Bel B
Bel C
Bel D
Bel A
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’ 446' 6.620" Baker TE S-5 SSSV
2 1008’ 1,006' ES Cementer
3 5,711’ 3,417' 3.813" X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’ 3,437' 3.958" Liner hanger / LTP Assembly
5 5,766’ 3,440' 3.958" Seal Stem
6 9,250’ 5,090’ - CIBP (01/17/25)
7 9,380’ 5,186’ - CIBP (01/16/25)
8 9,775’ 5,502’ - CIBP (01/13/25)
9 10,130’ 5,810’ - CIBP (01/08/25)
10 10,570’ 6,197’ - CIBP (10/29/24)
11 10,670’ 6,286’ - CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Bel Aa 8,634’ 8,662’ 4,702’ 4,717’ 28’ 01/21/25 Open
Bel Ba 8,833’ 8,847’ 4,814’ 4,822’ 14’ 01/20/25 Open
Bel Bb 8,856’ 8,872’ 4,828’ 4,837’ 16’ 01/20/25 Open
Bel Bd 8,954’ 8,965’ 4,889’ 4,896’ 11’ 01/19/25 Open
Del Be 9,000’ 9,004’ 4,919’ 4,922’ 4’ 01/19/25 Open
Bel Bf 9,022’ 9,028’ 4,934’ 4,938’ 6’ 01/19/25 Open
Bel Ca 9,064’ 9,074’ 4,962’ 4,968’ 10’ 01/18/25 Open
Bel Cb 9,084’ 9,094’ 4,975’ 4,982’ 10’ 01/18/25 Open
Bel Cc 9,103’ 9,113’ 4,988’ 4,995’ 10’ 01/18/25 Open
Bel Da 9,200’ 9,210’ 5,055’ 5,062’ 10’ 01/18/25 Open
Bel Db 9,218’ 9,224’ 5,068’ 5,072’ 6’ 01/18/25 Open
Bel Dc 9,233’ 9,238’ 5,078’ 5,082’ 5’ 01/18/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’ 2,012' 3.833" GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’ 3,395' 3.833" GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’ 12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
Updated By: JLL 01/23/25
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Bel Dd 9,263’ 9,283’ 5,099’ 5,144’ 20’ 01/15/25 Isolated (01/17/25)
Bel De 9,319’ 9,339’ 5,140’ 5,155’ 20’ 01/15/25 Isolated (01/17/25)
Bel Df 9,350’ 9,367’ 5,163’ 5,176’ 17’ 01/14/25 Isolated (01/17/25)
Bel Ea 9,390’ 9,400’ 5,193’ 5,201’ 10’ 01/14/25 Isolated (01/16/25)
Bel Eb 9,432’ 9,452’ 5,225’ 5,240’ 20’ 01/13/25 Isolated (01/16/25)
Bel Ha 9,795’ 9,811’ 5,519’ 5,533’ 16’ 01/11/25 Isolated (01/13/25)
Bel Jc 10,173’ 10,179’ 5,848’ 5,853’ 6’ 11/10/24 Isolated (01/08/25)
Bel Ma 10,386’ 10,396’ 6,035’ 6,044’ 10’ 11/9/24 Isolated (01/08/25)
Bel Mb 10,408’ 10,414’ 6,054’ 6,060’ 6’ 11/9/24 Isolated (01/08/25)
Bel Mc 10,424’ 10,444’ 6,068’ 6,086’ 20’ 10/31/24 Isolated (01/08/25)
Bel N 10,460’ 10,464’ 6,100’ 6,104’ 4’ 10/29/24 Isolated (01/08/25)
Bel Oa 10,502’ 10,508’ 6,137’ 6,142’ 6’ 10/29/24 Isolated (01/08/25)
Bel Ob 10,516’ 10,530’ 6,147’ 6,162’ 14’ 10/29/24 Isolated (01/08/25)
Bel P 10,578’ 10,584’ 6,204’ 6,210’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pb 10,602’ 10,608’ 6,226’ 6,231’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pc 10,629’ 10,643’ 6,249’ 6,262’ 14’ 10/17/24 Isolated (10/29/24)
Bel Qa 10,678’ 10,684’ 6,293’ 6,298’ 6’ 10/17/24 Isolated (10/27/24)
Bel Qb 10,742’ 10,756’ 6,349’ 6,362’ 14’ 10/17/24 Isolated (10/27/24)
Bel Qc 10,777’ 10,783’ 6,380’ 6,386’ 6’ 10/17/24 Isolated (10/27/24)
Bel Ra 10,825’ 10,835’ 6,423’ 6,432’ 10’ 10/17/24 Isolated (10/27/24)
Bel Rb 10,844’ 10,850’ 6,440’ 6,445’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rc 10,884’ 10,890’ 6,475’ 6,480’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rd 10,918’ 10,928’ 6,505’ 6,514’ 10’ 10/17/24 Isolated (10/27/24)
Bel Sa 10,946’ 10,956’ 6,530’ 6,539’ 10’ 10/16/24 Isolated (10/27/24)
Bel S 11,056’ 11,062’ 6,627’ 6,632’ 6’ 10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’ 6,728’ 10’ 10/16/24 Isolated (10/27/24)
_____________________________________________________________________________________
Updated By: JLL 01/31/25
PROPOSED
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
6
9
10
11
8
7
1
2
Sterling
Sands
3/4/5
Bel T
Bel Q
Bel S
Bel R
Bel P
Bel N
Bel O
Bel M
Bel J
Bel H
Bel E
Bel D
Bel B
Bel C
Bel D
Bel A
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’ 446' 6.620" Baker TE S-5 SSSV
2 1008’ 1,006' ES Cementer
3 5,711’ 3,417' 3.813" X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’ 3,437' 3.958" Liner hanger / LTP Assembly
5 5,766’ 3,440' 3.958" Seal Stem
6 9,250’ 5,090’ - CIBP (01/17/25)
7 9,380’ 5,186’ - CIBP (01/16/25)
8 9,775’ 5,502’ - CIBP (01/13/25)
9 10,130’ 5,810’ - CIBP (01/08/25)
10 10,570’ 6,197’ - CIBP (10/29/24)
11 10,670’ 6,286’ - CIBP (10/27/24)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Sterling ±5,945’ ±8,600’ ±3,551’ ±4,695’ ±2,655’ Future Proposed
Bel Aa 8,634’ 8,662’ 4,702’ 4,717’ 28’ 01/21/25 Open
Bel Ba 8,833’ 8,847’ 4,814’ 4,822’ 14’ 01/20/25 Open
Bel Bb 8,856’ 8,872’ 4,828’ 4,837’ 16’ 01/20/25 Open
Bel Bd 8,954’ 8,965’ 4,889’ 4,896’ 11’ 01/19/25 Open
Del Be 9,000’ 9,004’ 4,919’ 4,922’ 4’ 01/19/25 Open
Bel Bf 9,022’ 9,028’ 4,934’ 4,938’ 6’ 01/19/25 Open
Bel Ca 9,064’ 9,074’ 4,962’ 4,968’ 10’ 01/18/25 Open
Bel Cb 9,084’ 9,094’ 4,975’ 4,982’ 10’ 01/18/25 Open
Bel Cc 9,103’ 9,113’ 4,988’ 4,995’ 10’ 01/18/25 Open
Bel Da 9,200’ 9,210’ 5,055’ 5,062’ 10’ 01/18/25 Open
Bel Db 9,218’ 9,224’ 5,068’ 5,072’ 6’ 01/18/25 Open
Bel Dc 9,233’ 9,238’ 5,078’ 5,082’ 5’ 01/18/25 Open
Isolated Perforation Details on Page 2
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’ 2,012' 3.833" GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’ 3,395' 3.833" GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
FISH DETAILS
10,163’ 12/29/24 – Coil BHA LIH – OAL = 4 ’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
Updated By: JLL 01/31/25
PROPOSED
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
ISOLATED PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Bel Dd 9,263’ 9,283’ 5,099’ 5,144’ 20’ 01/15/25 Isolated (01/17/25)
Bel De 9,319’ 9,339’ 5,140’ 5,155’ 20’ 01/15/25 Isolated (01/17/25)
Bel Df 9,350’ 9,367’ 5,163’ 5,176’ 17’ 01/14/25 Isolated (01/17/25)
Bel Ea 9,390’ 9,400’ 5,193’ 5,201’ 10’ 01/14/25 Isolated (01/16/25)
Bel Eb 9,432’ 9,452’ 5,225’ 5,240’ 20’ 01/13/25 Isolated (01/16/25)
Bel Ha 9,795’ 9,811’ 5,519’ 5,533’ 16’ 01/11/25 Isolated (01/13/25)
Bel Jc 10,173’ 10,179’ 5,848’ 5,853’ 6’ 11/10/24 Isolated (01/08/25)
Bel Ma 10,386’ 10,396’ 6,035’ 6,044’ 10’ 11/9/24 Isolated (01/08/25)
Bel Mb 10,408’ 10,414’ 6,054’ 6,060’ 6’ 11/9/24 Isolated (01/08/25)
Bel Mc 10,424’ 10,444’ 6,068’ 6,086’ 20’ 10/31/24 Isolated (01/08/25)
Bel N 10,460’ 10,464’ 6,100’ 6,104’ 4’ 10/29/24 Isolated (01/08/25)
Bel Oa 10,502’ 10,508’ 6,137’ 6,142’ 6’ 10/29/24 Isolated (01/08/25)
Bel Ob 10,516’ 10,530’ 6,147’ 6,162’ 14’ 10/29/24 Isolated (01/08/25)
Bel P 10,578’ 10,584’ 6,204’ 6,210’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pb 10,602’ 10,608’ 6,226’ 6,231’ 6’ 10/28/24 Isolated (10/29/24)
Bel Pc 10,629’ 10,643’ 6,249’ 6,262’ 14’ 10/17/24 Isolated (10/29/24)
Bel Qa 10,678’ 10,684’ 6,293’ 6,298’ 6’ 10/17/24 Isolated (10/27/24)
Bel Qb 10,742’ 10,756’ 6,349’ 6,362’ 14’ 10/17/24 Isolated (10/27/24)
Bel Qc 10,777’ 10,783’ 6,380’ 6,386’ 6’ 10/17/24 Isolated (10/27/24)
Bel Ra 10,825’ 10,835’ 6,423’ 6,432’ 10’ 10/17/24 Isolated (10/27/24)
Bel Rb 10,844’ 10,850’ 6,440’ 6,445’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rc 10,884’ 10,890’ 6,475’ 6,480’ 6’ 10/17/24 Isolated (10/27/24)
Bel Rd 10,918’ 10,928’ 6,505’ 6,514’ 10’ 10/17/24 Isolated (10/27/24)
Bel Sa 10,946’ 10,956’ 6,530’ 6,539’ 10’ 10/16/24 Isolated (10/27/24)
Bel S 11,056’ 11,062’ 6,627’ 6,632’ 6’ 10/16/24 Isolated (10/27/24)
Bel T 11,160 11,170 6,719’ 6,728’ 10’ 10/16/24 Isolated (10/27/24)
KLU A-1
Well Head Rig Up
1
1
1
1
4 1/16" 15K Lubricator - 10 ft
100" Gooseneck
HR680 Injector Head
4 1/16" 10K Flow Cross, 2" 1502 10k Flanged
Valves
4 1/16" 15K Lubricator - 10 ft
API Flange Adapter 10K to 5K for riser/wellhead
Hydraulic Stripper 4 1/6" 15K
API Bowen CB56 15K
4 1/16" 10K Combi BOPs
Blind/Shear Ram
Pipe/Slip Ram
4 1/16" 10K bottom flange
4 1/16" 5K flanged Riser - 10 ft if necessary
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.
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.
From:Eric Dickerman
To:Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] FW: NCIU A-21 (Permit 224-086, Sundry 325-053) - Question
Date:Monday, February 10, 2025 12:15:20 PM
Mr. Davies,
The top of the Tertiary System Gas Pool at 5,485’ md / 3,329’ tvd.
Thank you,
Eric Dickerman
Hilcorp – CIO Ops Engineer
Cell: 307-250-4013
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Monday, February 10, 2025 10:56 AM
To: Eric Dickerman <eric.dickerman@hilcorp.com>
Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>
Subject: [EXTERNAL] FW: NCIU A-21 (Permit 224-086, Sundry 325-053) - Question
Eric,
I'm reviewing Hilcorp’s Sundry Application to perforate NCIU A-21 (PTD 224-086, Sundry 325-053).
Could Hilcorp please provide the depth for the top of Tertiary System Gas Pool in this well in both
MD and TVD?
Regards and Be Well,
Steve Davies
AOGCC
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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
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.
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: 12/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241205
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet
AN 15(GRANITE PT
ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf
BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf
END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG
MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL
MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey
MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey
MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey
MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch
MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey
MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch
MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT
MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24
MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug
NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf
PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT
PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT
PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT
PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf
Please include current contact information if different from above.
T39808
T39809
T39810
T39810
T39811
T39812
T39813
T39813
T39814
T39815
T39816
T39817
T39818
T39819
T39820
T39820
T39821
T39822
T39823
T39823
T39823
T39823
T39824
T39825
T39826
T39827
NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.05 14:52:46 -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:
Date: 10/30/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241030
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf
BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf
GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer
IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf
MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey
MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey
MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey
MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist
NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL
NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL
NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf
PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT
PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT
PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT
PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT
PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF
PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL
PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf
SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch
Please include current contact information if different from above.
T39726
T39727
T39728
T39732
T39733
T39734
T39735
T39736
T39737
T39738
T39739
T39739
T39740
T39741
T39742
T39742
T39743
T39744
T39744
T39745
NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.01 13:27:33 -08'00'
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.
From:Rixse, Melvin G (OGC)
To:Ryan Rupert
Cc:Juanita Lovett; Karson Kozub; Trevor Willms - (C); McLellan, Bryan J (OGC)
Subject:RE: NCIU A-21 Bond Log
Date:Tuesday, October 8, 2024 10:11:36 PM
Ryan,
Approved to perforate per sundry with top of perfs at 8633’ MD.
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: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Tuesday, October 8, 2024 10:39 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub
<kkozub@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com>; McLellan, Bryan J (OGC)
<bryan.mclellan@alaska.gov>
Subject: NCIU A-21 Bond Log
Mel-
Please see attached for NCIU A-21 cement log associated with the approved completion
sundry attached.
With your approval, if like to begin the perf work on this well Thursday 10/10. Let me know if
we have permission to proceed.
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
907-777-8503 (Office)
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, 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 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.
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: 10/04/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-21
PTD: 224-086
API: 50-883-20199-00-00
Final GeoTap Formation Pressure Tester (08/09/2024 to 09/04/2024)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
224-086
T39635
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.10.04 15:23:25 -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: 09/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-21
PTD: 224-086
API: 50-883-20199-00-00
FINAL LWD FORMATION EVALUATION LOGS (08/09/2024 to 09/04/2024)
x ROP, DGR, EWR-P4, ADR, ALD, CTN (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.
224-086
T39592
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.27 14:11:14 -08'00'
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):
11,394 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: Ryan Rupert
Contact Email:Ryan.Rupert@hilcorp.com
Contact Phone:(907) 777-8503
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: CT / N2 Operations
North Cook Inlet N/A Tertiary System Gas
6,925 11,346 6,882 2,764psi N/A
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
224-086
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20199-00-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-21
Length Size
Proposed Pools:
L-80
TVD Burst
5,766
8,430psi
MD
1,630psi
6,870psi
384'
3,501'
384'
5,909'
30"
9-5/8"
384'
5,909'
ѷ8,633 -ѷ11,193
5,655'
ѷ4,701 -ѷ6,748
6,923'4-1/2"
CO 68A
9/26/2024
4-1/2"
LTP & Baker TE-5 5,758 (MD) 3,437 (TVD) & 446 (MD) 446 (TVD)
11,391'
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 9:43 am, Sep 13, 2024
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2024.09.13 05:19:06 -
08'00'
Dan Marlowe
(1267)
324-528
SFD 9/18/2024
X
DSR-9/13/24
Tertiary System Gas
Perforate New Pool
BJM 9/19/24
10-404
CT BOP test to 3000 psi. Weekly BOP test frequency approved to CT campaign on the same leg of
the Tyonek platform.Submit CBL to AOGCC and obtain approval before perforating.
X
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.09.19 10:33:30 -08'00'09/19/24
RBDMS JSB 092324
Initial Completion
Well: NCIU (Tyonek) A-21
Well Name:NCIU (Tyonek) A-21 API Number:50-883-20199-00-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:224-086
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,439 psi @ 6,748’ TVD 9.8ppg at Deepest planned perf
Max. Potential Surface Pressure: 2764 psi Using 0.1 psi/ft
Brief Well Summary
Jackup Rig #151 finished drilling and completing Tyonek well A-21 on 9/8/24. The drilling rig is currently
sidetracking a second well on this same leg (#1). Once complete with that sidetrack, the jackup will leave the
platform for the season. A-21 is a closed system currently and is not open to the formation. This procedure
addresses the initial post-drill completion wellwork to get the well online. All planned perforations below are
within the Tertiary System Gas Pool as defined by CO 68A.
The goal of this project is to complete the well after the drilling rig leaves.
Pertinent wellbore information:
- TRSSSV installed
-Live GLV’s were already installed when the tubing was run
- 9/7/24
o CMIT-TxIA to 3000psi PASSED
o MIT-T to 3000psi PASSED (also confirmed liner integrity. No TTP was set)
- Inclination:
o Max = 70 degrees at 5,314’ MD
o Sail angle of ~65 degrees from 2,200 – 8,500’ MD
Coiled Tubing Procedure
1. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
a. Multiple wells planned for CT intervention on this leg (#1)
b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well
3. MU cleanout BHA
4. RIH to PBTD and swap well over to water if needed
5. Obtain CBL (may be executed on EL. TBD) Submit CBL to AOOGCC
6. RIH and blow well dry with nitrogen
a. Reverse circulate water out of wellbore (no perforations, passing MIT’s)
b. Want to evacuate all IA fluid through live GLV’s as well
7. RDMO CT
Initial Completion
Well: NCIU (Tyonek) A-21
E-Line Perf procedure
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
3. Ensure CBL approval from AOGCC before perforating
4. RIH and perforate Beluga gas sands from ±8,633’ - ±11,193’ MD (±4,701’ - ±6,748’ TVD) per RE/Geo
a. All proposed perfs within Tertiary System Gas Pool
b. Top pool is at top Sterling sands: 5,485’ MD / 3,329’ TVD
c. Bottom pool is below PBTD
d. Pressures:
i. 9-5/8” at 3,506’ TVD: LOT at 13.7PPG
ii. Worst case pressure could create a 13.3ppg at the top sundried perf (4701’ TVD)
5. RDMO EL
CONTINGENCY plug/patch: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and PT lines to 3000psi (or higher if needed)
2. Pressure up on tubing and displace water back into formation
3. MIRU E-line and pressure control equipment
4. PT lubricator to 250psi low / 3000psi high
5. Set 4-1/2” isolation plug or patch per OE
6. RDMO Nitrogen and EL
CONTINGENCY CT Cleanout: (if any zone brings in excessive fill and needs to be cleaned out)
1. MIRU Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3000psi high
3. MU FCO BHA
4. RIH and cleanout to PBTD or as deep as practical
a. Working fluid will be water (8.33ppg or greater)
b. Take returns to surface up the CT x tubing annulus
c. Add foam and nitrogen as necessary to carry solids to surface
d. Can use GL to assist with hole cleaning
5. Once cleanout is completed, blow well down with nitrogen
6. RDMO CT
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing (Fox energy)
4. Nitrogen procedure
Updated by CJD 9-9-2024
Current SCHEMATIC
North Cook Inlet Unit
NCIU A-21
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
RKB = 126.6’
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
130”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth Item
1 446’SSSV
2 1008’ ES Cementer
3 2,381’ GLM, 4.5" X 1.5'' FO-2 "
4 5,655’ GLM, 4.5" X 1.5'' FO-2 "
5 5,711’ X nipple 3.813” Profile
6 5,758’ Liner hanger / LTP Assembly
7 5,766’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
8-1/2”
hole
2
4
5/6/7
3
6
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
_____________________________________________________________________________________
Updated By: JLL 09/12/24
PROPOSED
North Cook Inlet Unit
Well: NCIU A-21
Date Completed: 9/7/2024
PTD: 224-086
API: 50-883-20199-00-00
PBTD = 11,346’ / TVD = 6,882’
TD = 11,394’ / TVD = 6,925’
1
2
Beluga
Sands
3/4/5
RKB = 126.6'
30”
12-1/4”
hole
8-1/2”
hole
4-1/2”
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 5,909’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,736’ 11,391’
TUBING DETAIL
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,766’
JEWELRY DETAIL
No Depth
(MD)
Depth
(TVD)ID Item
1 446’ 446' 6.620" Baker TE S-5 SSSV
2 1008’ 1,006' ES Cementer
3 5,711’ 3,417' 3.813" X-Nipple Giant Oil Tool - 3.813” Profile
4 5,758’ 3,437' 3.958" Liner hanger / LTP Assembly
5 5,766’ 3,440' 3.958" Seal Stem
PERFORATION DETAIL
Zone Top (MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±8,633' ±11,193' ±4,701' ±6,748' ±2,560' Future Proposed
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,381’ 2,012' 3.833" GLM, 4.5" X 1.5'' FO-2 "16 Dome 750 9/7/24
2 5,655’ 3,395' 3.833" GLM, 4.5" X 1.5'' FO-2 "24 Orifice 9/7/24
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 390 bbls Stg 2 - 428 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 359 bbls / T – 40 bbls
OTHER DETAILS
9,384' GCBD with RA tag in collar
10,387' GCBD with RA tag in collar
KLU A-1
Well Head Rig Up
1
1
1
1
4 1/16" 15K Lubricator - 10 ft
100" Gooseneck
HR680 Injector Head
4 1/16" 10K Flow Cross, 2" 1502 10k Flanged
Valves
4 1/16" 15K Lubricator - 10 ft
API Flange Adapter 10K to 5K for riser/wellhead
Hydraulic Stripper 4 1/6" 15K
API Bowen CB56 15K
4 1/16" 10K Combi BOPs
Blind/Shear Ram
Pipe/Slip Ram
4 1/16" 10K bottom flange
4 1/16" 5K flanged Riser - 10 ft if necessary
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.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-21
JBR 10/16/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:9
4-1/2" & 5" joints. Well Bay & Floor methane FP (both set points)- replace batteries for pass. Pits methane audible FP-recal for
a pass. Shaker H2S FP (both set points)- replace for a pass. CMV 5 FP-cycle for a pass. Blinds fail. R/T not witnessed. Chart of
R/T sent to J. Regg.
Test Results
TEST DATA
Rig Rep:Hebert/BoydOperator:Hilcorp Alaska, LLC Operator Rep:Sunderland/Dambacher
Rig Owner/Rig No.:Hilcorp 151 PTD#:2240860 DATE:8/20/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM240821212729
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 8
MASP:
2797
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
13 FPNo. Valves
1 PManual Chokes
2 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 2-7/8"x5-1/2"P
#2 Rams 1 Blinds F
#3 Rams 1 5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 3 3-1/16"&3-1/P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1950
200 PSI Attained P19
Full Pressure Attained P130
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P16@2350
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
FP FPMeth Gas Detector
FP FPH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P12
#1 Rams P9
#2 Rams P9
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9 9999
9
9
9
9
9
9
9
9
9
%OLQG5DPUHWHVWFKDUWDWWDFKHG
Well Bay & Floor methane FP Pits methane audible FP
Shaker H2S FP CMV 5 FP Blinds fail
FP
F
FP
FP
FP
FP
9
"0($$*OTQFDUCPQ4"."0($$*OTQFDUCPQ4".
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
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet, Tertiary System Gas Pool, NCIU A-21
Hilcorp Alaska, LLC
Permit to Drill Number: 224-086
Surface Location: 1254' FNL, 982' FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 1065' FSL, 1472' FEL, Sec 30, T12N, R9W, SM, AK
Dear Mr. Myers:
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 AOGCCreserves
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 AOGCCspecifically 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 AOGCCorder, 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 day of July 2024. 25
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2024.07.25 15:01:19
-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: 11,209' TVD: 6,822'
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:2509' to NCIU A-11A
16. Deviated wells:Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 64 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
8-1/2" 4-1/2" 12.6# L-80 GBCD 5,573' 5,636' 3,411' 11,209' 6,822'
Tieback 4-1/2" 12.6# L-80 Hyd 533 5,636' Surface Surface 5,636' 3,411'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
384'
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
NCIU A-21
North Cook Inlet Unit
Tertiary System Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Total Depth MD (ft):Total Depth TVD (ft):
022224484
MDSize
Plugs (measured):
St 1 L - 1902 ft3 / T - 252 ft3
St 2 L - 2333 ft3
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 1995 ft3 / T - 207 ft3
2797
2536' FSL, 2295' FWL, Sec 31, T12N, R9W, SM, AK
1065' FSL, 1472' FEL, Sec 30, T12N, R9W, 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
8328
18. Casing Program:Top - Setting Depth - BottomSpecifications
3479
12-1/4"9-5/8"47# L-80 DWC/C
(including stage data)
5,836'Surface Surface 5,836'3,500'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
Authorized Signature:
Authorized Name:
Production
Liner
Intermediate
Driven 384'
Drilling Manager
Monty Myers
30"~384
7/20/2024
3867' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
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):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback Assy.
LengthCasing Cement Volume
Conductor/Structural
Authorized Title:
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)
Drilling Manager
06/13/24
Monty M
Myers
By Grace Christianson at 11:23 am, Jun 24, 2024
BOP test to 3000 psi, Annular test to 2500 psi.
See additional MPD conditions of approval attached.
50-883-20199-00-00
DSR-6/25/24
224-086
BJM 7/24/24 SFD 6/26/2024*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.07.25 15:01:31 -08'00'07/25/24
07/25/24
RBDMS JSB 073024
NCIU A-21 (PTD 224-088)
Conditions of approval and Waiver to 20 AAC 25.033(b)(1)(A)
The following are conditions of ÍŕŕŘĺŽÍīϙťĺϙŪŜôϙÍϙîŘĖīīĖIJČϙƲŪĖîϙťēÍťϙîĺôŜϙIJĺťϙēÍŽôϙŜŪƯĖèĖôIJťϙîôIJŜĖťƅϙ
to overbalance the pressure of the uncased portion of the formations penetrated in the 8-3/4” hole
section of this well, which requires a waiver to 20 AAC 25.033(b)(1)(A). This waiver is conditional on
the following:
1.ϙaÍIJÍČôîϙŘôŜŜŪŘôϙ"ŘĖīīĖIJČϙϼa"ϽϙŜƅŜťôıϙĖŜϙťĺϙæôϙŪŜôîϙťĺϙÍŕŕīƅϙťēôϙŜŪŘċÍèôϙŕŘôŜŜŪŘôϙ
required to keep the open hole formations in an overbalanced state whenever the drilling
ƲŪĖîϙîôIJŜĖťƅϙĖŜϙĖIJŜŪƯĖèĖôIJťϙťĺϙıÍĖIJťÍĖIJϙĺŽôŘæÍīÍIJèôϙťĺϙťēôϙĺŕôIJϙēĺīôϙċĺŘıÍťĖĺIJŜϟ
2.ēôϙ>Iϯ[iϙŕŘôŜŜŪŘôϙĖŜϙŜŪƯĖèĖôIJťϙťĺϙıÍĖIJťÍĖIJϙѳ30 bbls kick tolerance with a 0.5 ppg kick
ĖIJťôIJŜĖťƅϙÍæĺŽôϙťēôϙēĖČēôŜťϙÍIJťĖèĖŕÍťôîϙŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôϟϙϙēĖŜϙĖŜϙÍϙŘôīÍťĖŽôīƅϙēĖČēϙħĖèħϙ
ťĺīôŘÍIJèôϙſēĖèēϙŕŘĺŽĖîôŜϙŜĺıôϙŘĺĺıϙċĺŘϙôŘŘĺŘϙĖIJϙa"ϙèēĺħôϙŜƅŜťôıϙċÍĖīŪŘôϙĺŘϙēŪıÍIJϙôŘŘĺŘŜϙ
associated with kick prevention anîϙſôīīϙèĺIJťŘĺīϙŘôŜŕĺIJŜôϟϙϙXĖèħϙťĺīôŘÍIJèôϙťĺϙæôϙŽôŘĖƱôîϙ
ŪŜĖIJČϙÍèťŪÍīϙ>Iϯ[iϙîÍťÍϙîôŘĖŽôîϙċŘĺıϙťēôϙťôŜťϙŕôŘċĺŘıôîϙÍċťôŘϙîŘĖīīĖIJČϙĺŪťϙťēôϙŕŘôŽĖĺŪŜīƅϙ
set casing shoe of this well. i@ ϙŽôŘĖƱèÍťĖĺIJϙĺċϙŜŪƯĖèĖôIJťϙ>Iϯ[iϙŘôŜŪīťŜϙŘôŗŪĖŘôîϙ
æôċĺŘôϙîŘĖīīĖIJČϙŕŘĺîŪèťĖĺIJϙēĺīô.
3.īīϙĖIJƲŪƄôŜϙťĺϙæôϙcirculated out per conventional well kill protocols, with closed BOP and
ŜīĺſϙŕŪıŕϙŘÍťôϟϙϙa"ϙŜƅŜťôıϙſĖīīϙIJĺťϙæôϙŪŜôîϙċĺŘϙèĖŘèŪīÍťĖIJČϙĺŪťϙĖIJƲŪƄôŜϠϙſēôťēôŘϙťēôϙĖIJƲŪƄϙ
occurred while drilling, while making a connection or while tripping, or while conducting
ÍIJƅϙĺťēôŘϙĺŕôŘÍťĖĺIJ.
4.ôťŪŘIJϙƲĺſϙŜťŘôÍıϙťĺϙæôϙŘĺŪťôîϙťēŘĺŪČēϙťēôϙƲĺſīĖIJôϙÍIJîϙƲĺſϙŕÍîîīôϙîĺſIJŜťŘôÍıϙĺċϙťēôϙ
a"ϙèēĺħôϙÍIJîϙ ĺŘôĺīĖŜϙƲĺſϙıôťôŘϙŜĺϙťēôϙîŘĖīīôŘϙèÍIJϙĺæŜôŘŽôϙèēÍIJČôŜϙťĺϙŘôťŪŘIJϙƲĺſϙŘÍťôϙ
ĖIJîôŕôIJîôIJťϙĺċϙťēôϙa"ϙŜƅŜťôıϟ
5.XĖèħϙſēĖīôϙîŘĖīīĖIJČϙĺŘϙſēĖīôϙťŘĖŕŕĖIJČϙîŘĖīīŜϙŘôŗŪĖŘôîϙſĖťēϙôÍèēϙťĺŪŘϙôŽôŘƅϙĺťēôŘϙîÍƅϙſēĖīôϙŪŜĖIJČϙ
ťēôϙa"ϙŜƅŜťôıϙæôČĖIJIJĖIJČϙťēôϙƱŘŜťϙîÍƅϙa"ϙĖŜϙŪŜôîϟϙ
6. TēôϙċĺīīĺſĖIJČϙÍîîĖťĖĺIJÍīϙîŘĖīīŜϙŜēÍīīϙæôϙèĺIJîŪèťôîϙſĖťēϙôÍèēϙťĺŪŘϙĖIJϙťēôϙƱŘŜťϙîÍƅϙťēôϙa"ϙ
ŜƅŜťôıϙĖŜϙŪŜôîϟϙ
a. Loss of MPD choke pressure while making connection. This drill will assume that the
loss of choke pressure results in a kick due to being underbalanced.
b.>ÍĖīŪŘôϙĺċϙťēôϙîŘĖīīŜťŘĖIJČϙƲĺÍťϙŘôŜŪīťĖIJČϙĖIJϙÍϙƲĺſϙŪŕϙťēôϙîŘĖīīϙŜťŘĖIJČϙîŪôϙťĺϙæôĖIJČϙ
underbalanced to the reservoir and because of U-ťŪæôϙôƯôèťϙſĖťēϙMPD pressure on
the choke.
IJϙÍîîĖťĖĺIJÍīϙèĺIJŜĖîôŘÍťĖĺIJϙċĺŘϙťēĖŜϙÍŕŕŘĺŽÍīϙĖŜϙťēôϙŘôīÍťĖŽôīƅϙīĺſϙŪIJèôŘťÍĖIJťƅϙċĺŘϙťēôϙıÍƄĖıŪıϙ
ŘôŜôŘŽĺĖŘϙŕŘôŜŜŪŘôŜϙĖIJϙťēĖŜϙēĺīôϙŜôèťĖĺIJϙîŪôϙťĺϙťēôϙıŪīťĖŕīôϙŕôIJôťŘÍťĖĺIJŜϙæôīĺſϙťēôϙƅĺIJôħϙīÍťċĺŘıϟϙϙ
Reservoir pressures are well understood and thus the risk ĺċϙÍϙħĖèħϙĖIJťôIJŜĖťƅϙĺċϙѳ͏ϟ͔ϙŕŕČϙÍæĺŽôϙıÍƄϙ
anticipated reservoir pressure is low.
A-21 Drilling Program
Tyonek
Sean McLaughlin
PTD
June 11, 2024
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. Planned Wellbore Schematic.............................................................................................................6
7. Drilling Summary...............................................................................................................................7
8. Mandatory Regulatory Compliance / Notifications.........................................................................8
9. R/U and Preparatory Work.............................................................................................................11
10. N/U 21-1/4” 2M Diverter..................................................................................................................12
11. Drill 12-1/4” Hole Section.................................................................................................................13
12. Run 9-5/8” Surface Casing...............................................................................................................15
13. Cement 9-5/8” Surface Casing.........................................................................................................18
14. ND/NU and Test casing ....................................................................................................................23
15. BOP N/U and Test.............................................................................................................................24
16. Drill 8-1/2” Hole Section...................................................................................................................25
17. Run 4-1/2” Production Liner...........................................................................................................26
18. Cement 4-1/2” Production Liner.....................................................................................................28
19. Wellbore Clean Up & Displacement...............................................................................................31
20. Run Completion Assembly...............................................................................................................31
21. BOP Schematic..................................................................................................................................33
22. Wellhead Schematic..........................................................................................................................34
23. Anticipated Drilling Hazards...........................................................................................................35
24. FIT Procedure...................................................................................................................................36
25. Choke Manifold Schematic..............................................................................................................37
26. Casing Design Information ..............................................................................................................39
27. 8-1/2” Hole Section MASP...............................................................................................................40
28. Plot (NAD 27) (Governmental Sections).........................................................................................41
29. Slot Diagram......................................................................................................................................42
Page 2 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
1. Well Summary
Well NCI A-21
Drilling Rig Rig 151
Leg & Slot Leg 1 / Slot 5
Directional plan wp01
Pad & Old Well Designation NA - Grassroots
Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing GL Comp
Target Reservoir(s)Beluga A-U
Kick off point NA
Planned Well TD, MD / TVD 11209’ MD / 6822’ TVD
PBTD, MD 11109’ MD
MASP 2797 psi
AFE Number
AFE Days
AFE Drilling Amount
Work String(s)5” 19.5# S135 NC50
RKB – AMSL 126.6’
MSL to ML 74.10’
Page 3 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
2. Management of Change Information
Date: June 11, 2024
Subject: Changes to Approved Permit to Drill
File #: NCI A-21 Drilling Program
Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an
approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work.
Sec Page Date Procedure Change
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
3. Tubular Program
Hole Section OD
(in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)Grade Conn Burst
(psi)
Collap
se
(psi)
Tensi
on (k-
lbs)
Conductor
(previously
installed)
30”Assume
29”--Assume
158#X-56 Weld 1630 230
12-1/4”9.625”8.681”8.525”10.625”47 L-80 DWC/C 6870 4750 1086
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288
** Minimum of 100’ overlap required between casing strings
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 5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k
Page 5 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
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 mmyers@hilcorp.com, cdinger@hilcorp.com,
sean.mclaughlin@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. Monty Myers: O: 907-777-8431 C: 907-538-1168
iii. 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 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
6. Planned Wellbore Schematic
Superseded
Updated by CJD 6-13-2024
Proposed SCHEMATIC
North Cook Inlet Unit
NCIU A-21
PTD: TBD
API: 50-883-XXXXX-00-00
PBTD = 11,130’ / TVD = 6,753’
TD = 11,209’ / TVD = 6,821’
RKB = 126.6’
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 5,836’
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 5,636’ 11,209’
4-1/2" Prod Tieback 12.6 L-80 IBT-M 3.958” Surf 5,636’
1 30”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth Item
1 ±500’ SSSV
2 ±1000’ ES Cementer
3 ±2,360’ GLM with Dummy 1-1/2” valve
4 ±4,573’ GLM with Dummy
5 ±4,626’ X nipple 3.813” Profile
6 ±5,636’ Seal Stem
7 ±5,636’ Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 383 bbls Stg 2 - 415 bbls
4-1/2” Est. TOC @ TOL (40% excess) L – 355 bbls / T – 37 bbls
8-1/2”
hole
2
4
5/6/7
3
6
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7. Drilling Summary
A-21 is a 11209’ MD / 6822’ TVD development gas well drilled from leg 1 slot #5 off the Tyonek platform.
The base plan is an infill wellbore to the Beluga U.
The well will be completed with a 4-1/2” gas lift tie-back completion.
Drilling operations is expected to commence approximately July 2024.
General sequence of operations pertaining to this drilling operation:
Rig Work
1. Rig 151 will MIRU over leg 1, slot 5
2. Rig 21-1/4” x 2M Diverter
3. MU 12-1/4” bit with 8” drilling tools (GR/RES)
4. Drill 12-1/4” hole to 5837’ MD. Run and cmt 9-5/8” casing (2 stages).
5. N/D riser and N/U casing head
6. Test casing to 3500 psi. Secure well with BPV and dryhole tree
7. N/U and test 13-5/8” x 5M BOP to 3000 psi, Rig up MPD equipment
8. MU 8-1/2” bit with 6-3/4” tools (Triple Combo LWD)
9. Mill shoe track with 20’ of new formation.
10. Perform FIT to 14.8 ppg EMW
11. Drill 8-1/2” production hole to 11209 MD, performing short trips as needed
x MPD equipment to be used as primary well control barrier
x NOV Agitator tool to be used to reduce stick slip if necessary
12. Swap well over to KWF. POOH w/ directional tools.
13. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
14. Perform Clean out run to polish bore, LDDP
15. Perform liner lap test to 3000 psi.
16. Run 4-1/2” gas lift completion.
17. Land hanger and test.MIT-T to 3000 psi, MIT-IA to 3000 psi
18. ND BOPE, NU tree and test void
Reservoir Evaluation Plan:
1. Surface hole: GR + Res LWD
2. Production Hole: Triple Combo LWD
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8. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that 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 3479 psi in the Beluga U sand (6822' TVD). MASP is
2797 psi with 0.1psi/ft gas in the wellbore.
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.
AOGCC Regulation Variance Requests:
x 20 AAC 25.033 variance request:Managed Pressure Drilling equipment and technique will be used
for primary well control in place of drilling mud while drilling the 8-1/2” production hole. Kill
weight fluid will be used for primary well control during surface hole and running liner.
Benefits of using MPD with hydrostatically underbalanced mud weight:
o Ability to utilize lighter mud weight and compensate for ECD difference through SBP (Surface
Back Pressure) to stay above PP/wellbore stability
o Improve ROP and minimize differential sticking
o Ability to increase or reduce EMW downhole by adjusting SBP, without going through the
process of displacing to new mud weight.
o More effective downhole pressure control when comes to high pressure or abnormal pressure
regimes.
Managed Pressure Drilling equipment and technique will be usedqggqpq
for primary well control in place of drilling mud while drilling the 8-1/2” production hole.
Page 9 June 11, 2024
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o Coriolis flowmeter is able to measure small flowrates difference (up to +/- 0.10% of flow rate
accuracy for liquid, technical specs sheet as per attached) thus able to identify influx or losses
before it's picked up by the conventional PVT system.
o Applying constant SBP can help to minimize ballooning and swabbing.
o Holding SBP during connections help to minimize pressure cycling in the sensitive formation
o With RCD and MPD Choke manifold in place, the drilling system is going to be closed loop all
the time where MPD chokes will be opening and closing automatically depending on flowrates
down the string to apply desired target SBP.
o While ensuring SBP is applied constantly (except during the cases of losses), any flow is
diverted away from the rig floor.
Equipment and Generic Flow path:
o Major Equipment includes:
1. MPD Choke Manifold Building (With MPD Choke Manifold)
o MPD Control Console (inside MPD Choke Manifold Building)
o Coriolis flowmeter spool (inside MPD Choke Manifold Building)
2. MPD Remote Control Panel
3. RCD Body
4. RCD Bearing assembly with sealing elements (installed into RCD Body)
5. Various piping (4” and 2”) and hoses (4” and 2”)
6. Isolation valves
o A general flow path diagram is as follows. An actual flow path diagram will be created during
rig up and prior to drilling with MPD.
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Contingency:
o There will be sufficient weighting material on location to bring the drilling mud up to KWF
weight.
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4 x 21-1/4” x 2M Hydril MSP diverter Function Test Only
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
Page 11 June 11, 2024
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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)
9. R/U and Preparatory Work
1. Mix WBM mud for 12-1/4” hole section.
2. Set test plug in wellhead prior to N/U riser to ensure nothing can fall into the wellbore if it is
accidentally dropped.
3. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30” conductor. 7” liners will
deliver 575 gpm @ 98% eff @ 3623 psi.
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10. N/U 21-1/4” 2M Diverter
1. N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 21-1/4” x 2 M riser on 28” landing ring.
x N/U 21-1/4” 2M diverter w/16” outlet.
x Knife gate, 16” diverter line.
2. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that
knife gate opens prior to annular closure.Annular element must close in less than 45 seconds.
3. Set wear bushing in wellhead.
4. Rig and Diverter Line Orientation on Tyonek Platform (Leg #1):
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11. Drill 12-1/4” Hole Section
1. 12-1/4” hole mud program summary:
x Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start with a
simple gel + FW spud mud at 9.2ppg.
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:8.9 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
400’ – 5837’8.9 – 9.5 80-120 20 - 40 35 - 55 <10 8.5 – 9.5
System Formulation:Aquagel / FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
BARAZAN D+
PAC-L /DEXTRID LT
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROID 41
caustic soda
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 25 ppb
as needed
if required for <10 API FL
5 ppb total
5 ppb total
4.0 ppb
as required for weight 8.8 – 9.2 ppg
0.1 ppb (8.5 –9.5pH)
0.1 ppb
AQUAGEL and BARAZAN D+ should be used to maintain rheology. Begin system with a 55 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be
prepared to increase the YP if hole cleaning becomes an issue. DEXTRID and/or PAC L should be used
for filtrate control. Background LCM (10 - 20 ppb total) BARACARBs/BAROFIBRE/STEELSEALs
should be used in the system while drilling the surface interval to prevent losses and strengthen the
wellbore. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so,
approval from town will be required prior to additions of lubricants. Additions of CON DET PRE-
MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when
penetrating high-clay content sections. Maintain the pH in the 8.5 – 9.5 range with caustic soda. Daily
additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Mix a ~50 bbl LCM pill prior to drilling out of the conductor, to be available for immediate use if losses
are seen drilling the Surface hole. The pill formulation will be the 50 ppb pill from the LCM tree. Mix
the recommended LCM material in thinned back base mud.
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Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole
conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology
once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have
targeted).
Sweep Formulations: 20 barrels mud, add 1.0 ppb BARAZAN D.
Additions of CON DET PREMIX are recommended when penetrating high-clay content sections to
reduce the incidence of bit balling and shaker blinding.
At TD, a Walnut “flag” (20 bbl pill with 15 ppb of Wallnut M) could be pumped to gauge hole washout
- to help calculate the required cement volume. The cement will then be pumped and drilling mud will
be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid.
o MU 12-1/4” milltooth bit with 8” Drilling tools (UBHO and directional only)
o Ensure BHA components have been inspected previously.
o Drift and caliper all components before M/U.
o Pump at 1000 gpm to clean the hole effectively.
2. TIH to top of fill in the 30” conductor. Fill was tagged at 333’ during prerig magnet run.
3. Displace hole to spud mud and begin drilling out cmt plug at 350’ to 400’. This plug will be approx. 50
– 100 ft thick. Drill ~400’ with milltooth bit. Run GYRO as needed.
4. PU GR/RES and 12-1/4” Kymera or PDC. Drill the remainder of the 12-1/4” hole section.
x GR/RES only for surface hole.
x Rationale for casing shoe depth is ~40’ TVD above CI sands and ~40’ TVD below disposal zone.
Same surface casing plan as A-14, A-15, A-16 drilled by Conoco in 2009 and A-17 and A-18 drilled
by Hilcorp in 2023.
x Pump at 900 - 1000 gpm. 900 gpm equates to an annular velocity of 170 fpm in the openhole, and
27 fpm in the 30” casing which is poor for effective hole cleaning. Short trips and sweep will be
required. Ensure shaker screens are set up to handle this flowrate.
x Circulate hole clean and pump sweep before dropping rate to prevent fall back and sticking.
Maximize drill string RPMs, Pump sweeps and 6rpm rheology (target 10) to ensure effective hole
cleaning.
x Utilize Inlet experience to drill through coal seams efficiently. Work through coal seams once
drilled.
x Keep swab and surge pressures low when tripping.
x Pull wiper trips as often as necessary.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Take MWD surveys every stand drilled.
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12. Run 9-5/8” Surface Casing
1. R/U and pull wear bushing.
2. R/U PESI (Volant) 9-5/8” casing running equipment
x Ensure 9-5/8” NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Plan to rig up Volant CRT if available
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location 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.
3. P/U shoe joint, visually verify no debris inside joint.
4. Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” DWC, 1 Centralizer 10’ from bottom w/ stop ring
1 joint – 9-5/8” DWC, NO Centralizer
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” DWC, 1 Free floating centralizer
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
This end up.
Bypass Baffle
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x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
5. Float equipment and Stage tool equipment drawings:
Page 17 June 11, 2024
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6. Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to 5 joints below the ES Cementer
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
7. Install the Halliburton Type H ES-II Stage tool so that it is positioned at ~600’ MD below the
conductor.
x Install free floating centralizers on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
Stage tool positioned at ~600’ MD below the
conductor
Page 18 June 11, 2024
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8. Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization: Every joint to just inside the conductor (TD to ~350’)
9. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary.
10. Slow in and out of slips.
11. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it
is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger.
12. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed
out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed.
13. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses
closely while circulating.
14. After circulating, lower string and land hanger in wellhead again. Cement returns will be out the 2 x 4”
side outlets. Ensure hose is in place to take returns and dump into the inlet over the side of the
platform.
13. Cement 9-5/8” Surface Casing
1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well. Ensure
mud & water can be delivered to the cementing unit at acceptable rates.
x Discuss how to handle cement returns at surface.
x Determine which pumps will be utilized for displacement, and how fluid will be fed to
displacement pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
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2. Document efficiency of all possible displacement pumps prior to cement job.
3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help
ensure any debris left in the cement pump or treating iron will not be pumped downhole.
4. R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs
to ensure done in correct order.
5. Fill surface cement lines with water and pressure test.
6. Pump remaining 60 bbls 10.5 ppg tuned spacer.
7. Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
8. Stage 1 cement volume based on annular volume + 40% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.3 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
TOC planned for 1000' MD, may need
to adjust cement volume or change
stage tool placement to avoid leaving
gap in coverage from 600' - 1000' MD.
Verified cement calcs -bjm
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9. Attempt to reciprocate casing during first stage cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and
continue with the cement job.
10. After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of mud
pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
11. Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug must be
bumped.
12. Land hanger.
13. Displacement calculation is in the Stage 1 Table above.
73 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point
during the job.
15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by
no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer. Ensure the free
fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if
the plugs are not bumped.
16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are
holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is
set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if
pressure must be held, this is to ensure the stage tool is not prematurely opened.
17. Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be
necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and
volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the
cement job.
18. Be prepared for cement returns to surface. Cement returns to be taken overboard. Ensure to flush out
any rig components, hard lines and BOP stack that may have come in contact with the cement.
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Second Stage Surface Cement Job:
19. Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
20. HEC representative to witness the loading of the ES cementer closing plug in the cementing head.
21. Fill surface lines with water and pressure test.
22. 73 bbls of Spacer is already in the casing string.
23. Mix and pump cmt per below recipe for the 2nd stage.
24. Cement volume based on annular volume + 40% open hole excess + 100 bbls. Job will consist of lead
only, TOC brought to surface. However, cement will continue to be pumped until clean spacer is
observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
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25. Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
26. After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud
pits.
27. Displacement volume is in the Stage 2 table above.
28. Monitor returns closely while displacing cement. Adjust pump rate if necessary. Cement return will be
taken from 2 x 4” outlets and sent overboard.
29. Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has
closed.
30. Close 4” valves on wellhead side outlet and monitor pressure build up.
31. R/D cement equipment. Flush out wellhead with FW.
32. Back out and L/D landing joint. Flush out wellhead with FW.
33. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in
lock downs.
34. Lay down landing joint and pack-off running tool.
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
x Note if casing 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
Lead Slurry
System EconoCem
Density 12.0 lb/gal
Yield 2.35 ft3/sk
Mix Water 13.92 gal/sk
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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
Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and
cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC.
14. ND/NU and Test casing
1. N/D the Diverter
2. N/U 11” 5M multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test to 3000 psi.
3. Test casing to 3500 psi. 30 min charted.
4. Mix 9.0 WBM mud for 8-1/2” hole section.
5. 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 400-500 gpm. This can be achieved with one or both pumps.
6. 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 KWF 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.
x MPD will be used to add pressure to the hydrostatic mud column to provide primary well control.
o PWD will be used to monitor the annular pressure and adjust surface pressure based on ECD.
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x KWF or a spike pill will be required when swapping out a BHA or running liner.
System Type:LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
5837’- TD 8.8-10.1 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
7. 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.
8. 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 while drilling ahead.
15. BOP N/U and Test
1. N/U 13-5/8” x 5M BOP as follows (top down):
x RCD for MPD (Beyond Energy)
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” 5M 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” 5M Shaffer Type SL single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
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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 adapter required
2. Run BOPE test plug.
3. 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 test plug. Confirm the correct valves are opened!!!
x Test VBRs on a 4-1/2” and 5” test joints (3000 psi test)
x Test Annular on 4-1/2” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
4. Pull test plug.
16. Drill 8-1/2” Hole Section
1. M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
2. TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool.
3. TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
4. Drill out shoe track and 20’ of new formation.
5. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean
up debris.
6. Conduct FIT to 14.8 ppg EMW. Chart test. Document incremental volume pumped (and subsequent
pressure) and volume returned.
x 14.8 ppg with 9.8 ppg BHP and 9.1ppg mud equates to an 83 bbl KTV.
x Send Results to AOGCC within 48 hrs.
7. POOH & LD Cleanout BHA
8. Drift & caliper all MWD components before M/U. Visually verify no debris inside components that
cannot be drifted.
9. Ensure TF offset is measured accurately and entered correctly into the MWD software.
10. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 400-500 gpm.
Page 26 June 11, 2024
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11. P/U 8-1/2” PDC bit and 6-3/4” Sperry Sun motor drilling assy w/ Agitator and triple combo (DEN,
POR, RES).
12. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the drop section
of the wellbore.
13. TIH to window. Shallow test MWD on trip in.
14. Drill 8-1/2” hole to 11209’ 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. Work through coal seams
once drilled.
x Keep swab and surge pressures low when tripping.
x See attached mud program for hole cleaning and LCM strategies.
x Ensure solids control equipment functioning properly and utilized to keep LGS to a
minimum without excessive dilution.
x Adjust ECD with MPD 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 swap well to KWF. KWF dependent on pressures observed while drilling.
Flow check well for 10 minutes.
16. TOH with drilling assembly, handle BHA as appropriate.
17. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure 5” NC50 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.
Adjust ECD with MPD as necessary to maintain hole stability
Page 27 June 11, 2024
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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). Centralizer
10’ from the bottom with stop ring
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Landing collar pup bucked up. No centralizer
x Centralizers will be run on 4-1/2” liner every joint to 8000’ and every other joint above
that.
x Ensure proper operation of float shoe & FC.
4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’, RA Tag 1000’ and 2000’ from bottom.
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 28 June 11, 2024
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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.
11. Set slowly in and pull slowly out of slips.
12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe 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.
18. 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.
Page 29 June 11, 2024
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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 cement per below recipe and volume below 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. Please independently verify with actual inputs.
Slurry Information:
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.3 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
Verified cement calcs -bjm
Page 30 June 11, 2024
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8. Drop DP dart and displace with KWF.
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.
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.
Page 31 June 11, 2024
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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
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
19. 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.
20. 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# IBT & Supermax
x Baker S-5 SSSV to be placed between 400’ and 450’ MD
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x 2 live GLM’s will be run at 2000’ and 3500’ TVD (1 full joint between X-nip and bottom
GLM pup)
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.
6. ND BOPE, NU tree, test void
7. Rig Down
Page 33 June 11, 2024
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21. BOP Schematic
Page 34 June 11, 2024
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22. Wellhead Schematic
Page 35 June 11, 2024
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23. 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.
Anti Collision:
N/A
Page 36 June 11, 2024
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Drilling Program
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24. 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 37 June 11, 2024
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APD xxx-xxx
25. Choke Manifold Schematic
Page 38 June 11, 2024
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Drilling Program
APD xxx-xxx
Page 39 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
26. Casing Design Information
Page 40 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
27. 8-1/2” Hole Section MASP
Page 41 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
28. Plot (NAD 27) (Governmental Sections)
Page 42 June 11, 2024
NCI A-21
Drilling Program
APD xxx-xxx
29. Slot Diagram
A-21
!""
# !
# !
-1500-75007501500225030003750450052506000675075008250True Vertical Depth (1500 usft/in)0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250Vertical Section at 18.56° (1500 usft/in)9 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011209NCIU A-21 wp01Start Dir 2º/100' : 400' MD, 400'TVDStart Dir 3º/100' : 600' MD, 599.84'TVDStart Dir 4º/100' : 800' MD, 798.86'TVDEnd Dir : 2238.15' MD, 1922.59' TVDStart Dir 3º/100' : 8435' MD, 4639.11'TVDEnd Dir : 9568.33' MD, 5400.75' TVDTotal Depth : 11209' MD, 6821.61' TVDTop_Sterling_XTop_Beluga_ATop_Beluga_ITop_Beluga_MBeluga T/U - TDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: NCIU A-21Water Depth: 101.00+N/-S +E/-W Northing EastingLatitudeLongitude0.00 0.00 2586725.65 332001.3761° 4' 36.3363 N 150° 56' 55.4920 WSURVEY PROGRAMDate: 2024-04-02T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool52.53 1000.00 NCIU A-21 wp01 (NCIU A-21) 3_Gyro-GC_Csg1000.00 5837.00 NCIU A-21 wp01 (NCIU A-21) 3_MWD+AX+Sag5837.00 11209.00 NCIU A-21 wp01 (NCIU A-21) 3_MWD+AX+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation3528.00 3401.37 5900.37 Top_Sterling_X4626.00 4499.37 8405.10 Top_Beluga_A5554.00 5427.37 9745.29 Top_Beluga_I5943.00 5816.37 10194.47 Top_Beluga_MREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-21, True NorthVertical (TVD) Reference:RKB @ 126.63usftMeasured Depth Reference:RKB @ 126.63usftCalculation Method: Minimum CurvatureProject:North Cook InletSite:North Cook Inlet UnitWell:Plan: NCIU A-21Wellbore:NCIU A-21Design:NCIU A-21 wp01CASING DETAILSTVD TVDSS MD Size Name3500.00 3373.37 5836.50 9-5/8 9 5/8" x 12 1/4"6821.61 6694.98 11209.00 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSecMD Inc Azi TVD +N/-S +E/-W Dleg TFace VSectTargetAnnotation1 52.53 0.00 0.00 52.53 0.00 0.00 0.00 0.00 0.002 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 400' MD, 400'TVD3 600.00 4.00 100.00 599.84 -1.21 6.87 2.00 100.00 1.04 Start Dir 3º/100' : 600' MD, 599.84'TVD4 800.00 7.76 50.36 798.86 6.20 24.16 3.00 -80.00 13.57 Start Dir 4º/100' : 800' MD, 798.86'TVD5 2238.15 64.00 18.00 1922.59 746.07 324.33 4.00 -34.77 810.49 End Dir : 2238.15' MD, 1922.59' TVD68435.00 64.00 18.00 4639.11 6043.16 2045.46 0.00 0.00 6379.92 Start Dir 3º/100' : 8435' MD, 4639.11'TVD79568.33 30.00 18.00 5400.75 6819.94 2297.85 3.00 -180.00 7196.64 End Dir : 9568.33' MD, 5400.75' TVD8 11209.00 30.00 18.00 6821.61 7600.13 2551.35 0.00 0.00 8016.94 Total Depth : 11209' MD, 6821.61' TVD
0
425
850
1275
1700
2125
2550
2975
3400
3825
4250
4675
5100
5525
5950
6375
6800
7225
South(-)/North(+) (850 usft/in)-1700 -1275 -850 -425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250
West(-)/East(+) (850 usft/in)
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
250500
7
5
0
1000
1250
1500
1750
2000
2250
2500
2750
3000
3250
3500
3750
4000
4250
4500
4750
5000
5250
5500
5750
6000
6250
6500
6750
6822
NCIU A-21 wp01
Start Dir 2º/100' : 400' MD, 400'TVD
Start Dir 3º/100' : 600' MD, 599.84'TVD
Start Dir 4º/100' : 800' MD, 798.86'TVD
End Dir : 2238.15' MD, 1922.59' TVD
Start Dir 3º/100' : 8435' MD, 4639.11'TVD
End Dir : 9568.33' MD, 5400.75' TVD
Total Depth : 11209' MD, 6821.61' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3500.00 3373.37 5836.50 9-5/8 9 5/8" x 12 1/4"
6821.61 6694.98 11209.00 4-1/2 4 1/2" x 8 1/2"
Project: North Cook Inlet
Site: North Cook Inlet Unit
Well: Plan: NCIU A-21
Wellbore: NCIU A-21
Plan: NCIU A-21 wp01
WELL DETAILS: Plan: NCIU A-21
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586725.65 332001.37 61° 4' 36.3363 N 150° 56' 55.4920 W
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
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0.000.751.502.253.00Separation Factor0 500 100015002000250030003500400045005000550060006500700075008000850090009500Measured Depth (1000 usft/in)NCIU A-18A-08NCIU B-04 wp01B-02SUNFISH 3A-12NCI A-12ANCI A-12BB-01AB-01NCIU B-03AB-03NCI A-17NCIU A-13NCIU A-13PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: Plan: NCIU A-21 NAD 1927 (NADCON CONUS) Alaska Zone 04Water Depth: 101.00+N/-S+E/-W NorthingEastingLatitude Longitude0.000.002586725.65 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 CurvatureCASING DETAILSTVD TVDSS MD Size Name3500.00 3373.37 5836.50 9-5/8 9 5/8" x 12 1/4"6821.61 6694.98 11209.00 4-1/2 4 1/2" x 8 1/2"SURVEY PROGRAMDate: 2024-04-02T00:00:00 Validated: Yes Version: Depth From Depth ToSurvey/PlanTool52.53 1000.00 NCIU A-21 wp01 (NCIU A-21) 3_Gyro-GC_Csg1000.00 5837.00 NCIU A-21 wp01 (NCIU A-21) 3_MWD+AX+Sag5837.00 11209.00 NCIU A-21 wp01 (NCIU A-21) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)500 100015002000250030003500400045005000550060006500700075008000850090009500Measured Depth (1000 usft/in)NCIU A-18 PB1NCIU A-18 PB1NCIU A-18NCIU A-18A-08NCIU A-10BNCIU A-10BA-10AA-10AA-10A-10NCIU B-04 wp01NCI A-03AA-03A-05A-05NCIU A-14NCIU A-16NCIU A-16NCIU A-15B-02SUNFISH 3A-12NCI A-12ANCI A-12BNCI A-12BNCI A-01ANCI A-01AA-01A-01A-11A-11NCI A-11ANCI A-11AA-06B-01AB-01A-02A-07NCIU A-09ANCIU A-09PB1A-09NCIU B-03AB-03A-04NCI A-04ANCI A-17NCI A-17NCI A-17 PB1NCIU A-13NCIU A-19NCIU A-19NCIU A-19 wp02NCIU A-19 wp02NCI A-20NCI A-20 wp02NCI A-20 wp02GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference52.53 To 11209.00Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-21Wellbore: NCIU A-21Plan: NCIU A-21 wp01Ladder/S.F. Plots
1
Christianson, Grace K (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Wednesday, July 3, 2024 10:26 AM
To:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry
Request
Yes, The rig up, equipment, procedures, and plan will be the same on A-19 and A-21 as it is on the current well, A-
20.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Wednesday, July 3, 2024 9:54 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: FW: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Sean,
I assume this information is applicable to NCIU A-19 and NCIU A-21. I plan to attach it to the sundries as
reference. Let me know if anything has changed.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, June 20, 2024 10:54 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Bryan,
If the mud pump is stopped the MPD choke will automatically be maintaining a set pressure. The MPD choke will
automatically trap pressure in the event of a pump shut down. The choke pressure will be set to maintain a
constant BHP. The driller doesn’t need to step the pump down or consult with the MPD supervisor. Per the
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
2
AOGCC concerns the revised procedures keep the systems independent. The driller can shut down pumps and
shut in at will. The MPD chokes will prevent a sudden drop in surface pressure if the pumps are stopped suddenly.
For reference, the proposed MPD kit is a more advanced system than in use on the CTD rigs. In those operations
when the pump speed is changed the choke is manually changed. If the pump stops suddenly then the well will
Ʋow until the choke is shut in.
Both crews drilled to these standing orders yesterday. There was no confusion in responsibilities.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, June 20, 2024 10:15 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Sean,
For kick while drilling, can you describe what will be happening with the MPD choke during the period between
stopping the pump (Highlighted in yellow in the standing orders below) and upper pipe ram sealing around the drill
pipe. Does the MPD choke system automatically trap pressure when pumps go down? If so, how is the pressure
level determined? Does the driller need to step the pump rate down slowly to allow the MPD choke to adjust
pressures, or will the driller just turn the pumps oƯ immediately, like a switch? If the latter, the sudden drop in
surface pressure resulting from pumps going oƯ will result in a period of increased Ʋow until the pipe rams seal
around the drill pipe.
Even with the simpliƱed approach for MPD, there are still some subtle diƯerences when using underbalanced
Ʋuids. These diƯerences need to be clear so there is no confusion in the heat of the moment.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, June 20, 2024 9:27 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: RE: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Bryan,
Here is the additional information you requested:
Kick while drilling: If Ʋow is observed the well will be shut in per standing orders (attached). The pumps will be
shut down and the upper pipe rams closed. The kick will be handled through conventional well control
equipment. This action can happen independent of MPD operations. The MPD annular will be in use and the well
is being drilled on a choke so MPD may shut in to arrest Ʋow prior to the well control equipment being activated.
Kick while making a connection: : If Ʋow is observed the well will be shut in per standing orders (attached). The
well can be shut in independently from MPD operations as back pressure is being applied above the well control
equipment. The upper pipe rams can be shut in at will. Again, the MPD annular will be in use and the well is on a
choke so MPD may shut in to arrest Ʋow prior to the well control equipment being activated.
Please reach out with any further questions. The intent of this revised plan was to ease the AOGCC’s concerns
and make well control operations conventional. All the focus will be on holding back pressure on the well to stay
in an overbalance state. This is very similar to CTD operations and a common MPD technique.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Wednesday, June 19, 2024 5:19 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
The sundry application is not going to be approved. There’s insuƯicient information to support the waiver.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
4
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Wednesday, June 19, 2024 3:55 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Bryan,
What is the status of the A-20 Change to Approved program?
sean
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Monday, June 17, 2024 3:30 PM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: McLellan, Bryan J (CED <bryan.mclellan@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: ***Please Expedite***NCIU A-20 (PTD #224-065) 10-403 Sundry Request
Hello,
Please expedite.
Please see attached electronic distribution for NCIU A-20 (PTD #224-065). Please let me know if you have any
questions. Thanks!
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
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
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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.
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.
5
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.
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.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(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.
NORTH COOK INLET
NCIU A-21
TERTIARY GAS
224-086
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-21Initial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240860NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes Surf Loc & Top Prod Int lie in ADL0017589; TD lies in ADL0037831.2 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 564570 - governed by CO 68A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2797 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Lower Sterling reservoirs are expected to be under-pressured (~ 8.1 ppg EMW). These depleted36 Data presented on potential overpressure zonesNA reservoirs may cause lost circulation. Mitigation discussed on p. 37, and LCM materials will be available37 Seismic analysis of shallow gas zonesNA onsite. The Beluga A to H production interval is expected to be normally pressured (~ 8.3 ppg). The38 Seabed condition survey (if off-shore)NA underlying Beluga I through U intervals are expected to be over-pressured (~ 9.9 ppg).39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/26/2024ApprBJMDate7/24/2024ApprSFDDate6/26/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateExpected pressure range is 0.42 to 0.514 psi/ft (8.1 to 9.9 ppg EMW). Operator's planned mud program appears sufficient to control anticipated pressures and maintain wellbore stability. SFD*&:JLC 7/25/2024
