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HomeMy WebLinkAbout223-033Nolan 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-18 50883201890000 223033 4/5/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.28 08:42:09 -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):
10,117 N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
CO 68A
4/3/2025
4-1/2"
LTP & TR-SCSSSV 4,639 (MD) 3,093 (TVD) & 459 (MD) 459 (TVD)
10,088'
Perforation Depth MD (ft):
8,915 - 9,486
5,449'
5,937 - 6,498
7,094'4-1/2"
30"
9-5/8"
384'
4,875'
MD
1,630psi
6,870psi
384'
3,202'
384'
4,875'
Length Size
Proposed Pools:
L-80
TVD Burst
4,684
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-033
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20189-00-00
Hilcorp Alaska, LLC
Other: CTCO, N2 Operations
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
N Cook Inlet Unit A-18
N Cook Inlet Tertiary System Gas Same
7,122 9,740 6,749 1,911psi 9,740
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 3:19 pm, Mar 24, 2025
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.03.24 14:57:48 -
08'00'
Dan Marlowe
(1267)
325-162
4/3/2025
* BOPE test to 3000 psi.
MGR27MAR25
10-404
SFD 3/25/2025
Perforate
DSR-4/1/25*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.04.02 15:26:30 -08'00'04/02/25
RBDMS JSB 040325
Fill clean out and Perforate
Well: NCIU A-18
Well Name:NCIU A-18 API Number:50-883-20189-00-00
Current Status:Online gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-033
First Call Engineer:Eric Dickerman 307-250-4013
Second Call Engineer:Casey Morse 907-777-8322
Maximum Expected BHP:2,582 psi at 6,710’ tvd Shut in BHP survey – (12/18/23)
Max. Potential Surface Pressure (MPSP):1,911 psi Using 0.1 psi/ft gradient to surface
Applicable Frac Gradient:0.77 psi/ft using 14.8 ppg EMW -FIT at the 9-5/8” window
(9/13/23)
Shallowest Allowable Perf TVD:MPSP/(0.77 - 0.1) = 1,911 psi / 0.67 = 2,852‘ tvd
Top of Applicable Gas Pool:5,037’ md / 3,279’ tvd – Tertiary System Gas Pool CO 68
Brief Well Summary
NCIU A-18 was completed 10/2/2023 and perforated in the Lower Beluga. The well was a steady producer until
December 2024, when solids started to accumulate in the surface equipment. Since then, the well has been
produced choked back to a lower rate. On 3/23/25 slickline tagged at 9,287’ rkb, leaving the bottom three
intervals under fill.
Objective:
Cleanout the production interval. Add Lower Beluga perforations.
Notes on wellbore condition:
- SSSV: Well is completed with a tubing retrievable subsurface safety valve.
- Maximum inclination is 63.63 deg at 5,284’ md.
- 3/23/2025:
o Slickline tagged fill at 9,287’.
Fill clean out and Perforate
Well: NCIU A-18
Coiled Tubing Procedure:
1. MIRU Fox Energy offshore Coiled Tubing #9 and pressure control equipment.
2. Pressure test lubricator to 250 psi low / 3,000 psi high.
a. Provide AOGCC with 48 hr BOP test witness notification.
3. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to CIBP at 9,740’.
a. Working fluid will be 6% KCl (8.6ppg).
b. Take returns to surface up the CT x tubing annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
4. RIH and blow well dry with nitrogen.
5. RDMO CT.
6. Repeat coil cleanout as needed to allow Eline to reach target perforation intervals.
Eline Perf procedure:
7. MIRU Eline and pressure control equipment.
8. Pressure test lubricator to 250 psi low / 3,000 psi high.
9. RIH and perforate Beluga gas sands from ± 8,800 - ± 8,970’ md (± 5,824’ - ± 5,991’ tvd) as per RE/Geo.
a. All proposed perforations are within Tertiary System Gas Pool.
10. RDMO Eline.
CONTINGENCY Eline plug: (if any zone makes unwanted solids or water)
11. RU nitrogen to tubing and pressure test lines to 3,000 psi (or higher if needed).
12. Pressure up on tubing to displace water back into formation.
13. MIRU Eline and pressure control equipment.
14. Pressure test lubricator to 250 psi low / 3,000 psi high.
15. Set CIBP for water/solids shut off per OE.
16. RDMO Nitrogen and Eline.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing (Fox energy)
4. Nitrogen procedure
_____________________________________________________________________________________
Updated By: JLL 01/02/24
SCHEMATIC North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD =9,740’ MD / 6,749’TVD
TD = 10,117’ MD / 7,122’ TVD
U1 –
U7
4/5
6
1
2
3
RKB = 66.6’
S1 –
S-2
R-1
Q-2
P-1
M-4
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
TOW
4,875’
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 TXP 8.681” Surf 4,875’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ Giant Oil Tools - TR-SCSSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
6 9,740’ 6,749’ CIBP (12/15/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2”CBL shows ToC at 4,690’MD (12/4/23)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
M-4 8,915’ 8,921’ 5,937’ 5,943’ 6’ 12/22/23 Open
P-1 9,047’ 9,053’ 6,066’ 6,072’ 6’ 12/21/23 Open
Q-2 9,164’ 9,171’ 6,181’ 6,188’ 7’ 12/21/22 Open
R-1 9,309’ 9,329’ 6,324’ 6,343’ 20’ 12/20/23 Open
S-1 9,377‘ 9,403‘ 6,391’ 6,416’ 26’ 12/17/23 Open
S-2 9,477’ 9,486’ 6,489’ 6,498’ 9’ 12/15/23 Open
U-1 9,768’ 9,778’ 6,777’ 6,787’ 10’ 12/09/23 Isolated 12/15/23
U-5 9,900’ 9,910’ 6,907’ 6,917’ 10’ 12/09/23 Isolated 12/15/23
U-7 9,966’ 9,972’ 6,973’ 6,979’ 6’ 12/08/23 Isolated 12/15/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’SFO-1 Dome 11/22/23
2 4,573’ 3,062’SFO-1 Orifice 11/22/23
NOTE
7,312’ RA Marker
8,438’ RA Marker
_____________________________________________________________________________________
Updated By: EPD 03/24/25
PROPOSED North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD =9,740’ MD / 6,749’ TVD
TD = 10,117’ MD / 7,122’ TVD
U1 –
U7
4/5
6
1
2
3
RKB = 66.6’
S1 –
S-2
R-1
Q-2
P-1
M-4
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
TOW
4,875’
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 TXP 8.681” Surf 4,875’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ Giant Oil Tools - TR-SCSSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
6 9,740’ 6,749’ CIBP (12/15/23)
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2”CBL shows ToC at 4,690’MD (12/4/23)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
M ±8,800’ ±8,970’ ±5,824’ ±5,991’ ±170’ Future Proposed
M-4 8,915’ 8,921’ 5,937’ 5,943’ 6’ 12/22/23 Open
P-1 9,047’ 9,053’ 6,066’ 6,072’ 6’ 12/21/23 Open
Q-2 9,164’ 9,171’ 6,181’ 6,188’ 7’ 12/21/22 Open
R-1 9,309’ 9,329’ 6,324’ 6,343’ 20’ 12/20/23 Open
S-1 9,377‘ 9,403‘ 6,391’ 6,416’ 26’ 12/17/23 Open
S-2 9,477’ 9,486’ 6,489’ 6,498’ 9’ 12/15/23 Open
U-1 9,768’ 9,778’ 6,777’ 6,787’ 10’ 12/09/23 Isolated 12/15/23
U-5 9,900’ 9,910’ 6,907’ 6,917’ 10’ 12/09/23 Isolated 12/15/23
U-7 9,966’ 9,972’ 6,973’ 6,979’ 6’ 12/08/23 Isolated 12/15/23
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’SFO-1 Dome 11/22/23
2 4,573’ 3,062’SFO-1 Orifice 11/22/23
NOTE
7,312’ RA Marker
8,438’ RA Marker
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.
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: 5/9/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240509
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 3-07A 50029219110100 198147 4/17/2024 HALLIBURTON MFC
END 3-25B 50029221250200 203021 3/31/2024 HALLIBURTON PPROF
MPU J-16 50029226150000 195169 3/28/2024 HALLIBURTON WFL-TMD3D
NCIU A-18 50883201890000 223033 5/1/2024 READ
Multiple Array
PProf
PBU B-05D 50029202760400 213069 4/24/2024 HALLIBURTON RBT
PBU C-16C 50029204380300 213191 4/26/2024 HALLIBURTON RBT
PBU D-18B 50029206940200 215001 4/21/2024 HALLIBURTON RBT
TBF A-07 50733200360000 167046 4/17/2024 HALLIBURTON RBT
TBF A-18 50733201430000 168076 4/16/2024 HALLIBURTON RBT
Please include current contact information if different from above.
T38771
T38772
T38773
T38774
T38775
T38776
T38777
T38778
T38779
Multiple Array
NCIU A-18 50883201890000 223033 5/1/2024 READ PProf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.13 12:46:46 -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:Wilson, Greg C (OGC)
To:Coldiron, Samantha J (OGC)
Subject:FW: Report on NCIU A-18 Well Control Event
Date:Monday, April 29, 2024 3:09:23 PM
For the file.
Gregory Wilson
Commissioner
Alaska Oil and Gas Conservation Commission
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 AOGCC at 907-793-1223 or greg.wilson@alaska.gov.
From: Luke Saugier <lsaugier@hilcorp.com>
Sent: Monday, April 29, 2024 3:04 PM
To: Huber, Brett W (OGC) <brett.huber@alaska.gov>; Chmielowski, Jessie L C (OGC)
<jessie.chmielowski@alaska.gov>; Wilson, Greg C (OGC) <greg.wilson@alaska.gov>
Subject: Report on NCIU A-18 Well Control Event
Commissioners,
Thank you for sharing the findings from the 3rd party report on the NCIU A-18 well control event we
experienced last year. I’ve reviewed this with my direct reports and the drilling team and we found
some valuable insights on how we can get better. I think reports by 3rd party experts with broad
industry experience are particularly helpful in establishing best practices and helping us understand
industry norms. Again, thank you for commissioning the report and sharing the findings.
Respectfully,
Luke Saugier
Hilcorp Alaska
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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
April 16, 2024
Mr. Monte Myers
Drilling Manager
Hilcorp Alaska LLC
P.O. Box 244027
Anchorage, AK 99524-4027
Re: Review of Well Control Event – Enterprise Rig 151
North Cook Inlet Unit A-18 Well (PTD 2230330)
Dear Mr. Myers:
By letter dated October 2, 2023, Hilcorp Alaska LLC (Hilcorp) was notified that the Alaska Oil
and Gas Conservation Commission (AOGCC) initiated an investigation of the well control event
that occurred while drilling North Cook Inlet Unit A-18. The AOGCC hired an independent 3rd
party to review the August 2023 well control event. The scope of this review included the actions
leading up to the well control event through the steps taken to regain well control. The objective
was to evaluate the well control event and identify how to prevent its recurrence. The AOGCC
made several requests for information during the review and appreciates Hilcorp’s timely
responses.
Attached please find a copy of the report Findings in the NCIU A-18 Well Control Incident which
was prepared by Dr. Frederick E. Beck, Endeavor Management Company. Dr. Beck’s education,
expertise, and experience are well suited for this review, and we believe his findings provide
valuable learnings for AOGCC and Hilcorp.
The AOGCC entered the North Cook Inlet Unit A-18 well control review with the intent to better
understand the event, identify the root cause(s), and to provide a post-event assessment that
provides the opportunity for education and improvement. As such, AOGCC does not intend to
pursue any enforcement actions in connection with the well control event. Hilcorp is encouraged
to share and review the report internally and with its drilling contractors.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
Attachment
cc: P. Sherry (DOL)
B. McLellan
J. Regg
Brett W. Huber, Sr.
Digitally signed by Brett W. Huber,
Sr.
Date: 2024.04.16 16:23:45 -04'00'
1 |
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Report of Findings in the NCIU A-18 Well Control Incident
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Report of Findings, Dr. Frederick E. Beck
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Ǥ
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Ǥ ͶǦͳȀʹdz Ǥ
ǡ ͶʹǯͺȀͳͶǤ
2 |
Ǥ
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ǡ
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ǡ͵ͳͶǯ Ǥ Ǯͳʹ
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͵ͳͶǯǡǡ
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Ǥ
ȋ ͳȌ ǡ ǡǦ Ǥ
Well Kill Attempts
ͳʹ ȋ
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ǡ Ǥ ʹͳʹǤ
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Ͳ
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ͳͷǣͲǣͳʹ ͳͷǣ͵ǣͲͲ ͳǣͲͶǣͶͺ ͳǣ͵͵ǣ͵ ͳǣͲʹǣʹͶ ͳǣ͵ͳǣͳʹ ͳͺǣͲͲǣͲͲ ͳͺǣʹͺǣͶͺ ͳͺǣͷǣ͵
Figure 1 - Kick, Shut-In and Initial Circulation
ȋȌ ȋȌ ȋȌ
ȋȌ ȋȌ
͓ʹǣ
3 |
Ǥ ͳǤ
Ǥ
͓͵ǣȋͳͺǣͲͲͺȀͳͺȌ ǡǮǯǯǡͻͷ
ͳͲǤͲȋ̷ʹǤͺǡȌǤ
Ǥ Ǧ
ǡ ͳ ͲǤ
͓ͶǣȋʹʹǣͲͲͺȀͳͺȌǯȋ̷ʹǤͺȌ
ͳͲǤͲǤ ʹͷͻ
ǡ ǤͻͲΨǤ
ǦͲ Ͳ Ǥ͵Ͳǡ
ͳ͵ ͳͻͻǡ Ͳ
Ǥ ͳͲǤͲǡ
ͳͺͷǤ
͓ͷǣȋʹ͵ǣ͵ͲͺȀͳͺȌ ǯȋ̷
͵Ǥͻ͵ǤͶȌ ʹͷΨͷͲΨͳͲͲ
ȋȌǡͷΨͳͷǡͳͲͲΨ Ǥ
ʹͲͲǤ ǡ ͶͲ
͵ͷͲǤ
͓ǣȋͲ͵ǣ͵ͲͺȀͳͻȌ ǡͶ͵
ȋ̷͵ǤͷȌ ͳͲͲǤ
ͲͶǣ͵ͲͺȀͳͻǤ ͷͷͳǤ
ͷͲͳͲǤͳǡͲǤ
͓ǣȋͲͻǣ͵ͲͺȀͳͻȌͷʹǤͷȋ̷͵ǤͷȌͳͲͲǤ
Ǧ Ͳ ͲǤ
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Ͳ
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ͶͲͲ
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Ͳ ͷͲͲͲ ͳͲͲͲͲ ͳͷͲͲͲ ʹͲͲͲͲ ʹͷͲͲͲ ͵ͲͲͲͲ ͵ͷͲͲͲ
Figure 2 - Pump Operations Following Shut-In
ȋȌ ȋ̴̴Ȍ ȋȌ
1& 2
3 4
5
6 7
8 9 10
11
12
4 |
͓ͺǣȋͳʹǣ͵ͲͺȀͳͻȌ ȋ̷ʹǤͷȌ
ͳͷΨǤʹͶ͵ Ǥ
ǡȋǮǯȌ
ǡͳ͵Ǥͺ Ǥ Ǥ
͓ͻǣȋͳͷǣ͵ͲͺȀͳͻȌ ȋ̷ʹǤͷȌ
Ǥͷǡ
ͶͳͶǤ
͓ͳͲǣȋͳͺǣͲͲ ͺȀͳͻȌ ȋ̷ ʹǤͷ Ȍǡ
ͷͲΨʹͲǤ ǡʹʹͺͶͷʹ
Ǥǡ Ͳ ͲͳǤ
Ǥ ǡ ǤͳͲ
ǦǤ ͵ͲͲǡ ͲǤ
͓ͳͳǣȋͲʹǣͲͲͺȀʹͲȌ ȋ̷͵ǤͷȌǡͷͺ
ͳͻ͵ǤʹͶǡͺͲǤǦǤ Ͳǡ ͲǤ
ʹͳʹǤǡͷͲ͵ǡʹͳͲǡ ͵͵ΨǤ
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Ǥ
Ǥ
͓ͳʹǣȋͳͻǣͲͲͺȀʹͲȌ͵ȀǡͳͲͶȋ̷
ȌǤͺͲǤǡ ǡ
Ǥ͵ͶǤͷǡȋͳͶȌǡͷͷȋͻȌǤ ǡ
ǤͷǤʹǤ
ͳͷǣͲͲͺȀʹͳǡ Ǥ
ǡ ǡ
ȋȌ Ǥͳͺǣ͵ͲͺȀʹǤ
ͻǦͷȀͺdz ͺǦͳȀʹdzǤ
ȋ ͳͶǡ
Ȍǡ
ͳͲǡͳͳǯȀͳʹʹǯǡͶǦͳȀʹdz Ǥ
Observations and Opinions
ͳȌ ͳ
ǯȋ ͓͵Ȍǡ
Ǥ
ʹȌ Ǧ͵ȀͶdz ǡ
ǡ ȋȌǡ ǡ
ȋ
ȌǤͺǦͳȀʹdzǦ Ǥ
5 |
͵Ȍ Ǥ ȋȌ
Ǥ
ͶȌ ȋǦȌ Ǥ
Ǥ
ǤǮ
ǯ ǡ
Ǥ
ͷȌ ͺͷͻǯȋͺȀͳͺȌ
ǤͲ
ȋDzdzȌǡ
Ǥ
Ǥ ǡ
Ǥ
Ȍ Dzdzǡ
Ǥǡ Ͷ
Ǥ Ǥ
ͳͶͺ ǡͷ
ʹǤͷǦʹǤͷǡͷͺǤ
ǡ
Ǥ
Ȍ ǡͻ
͵ͺǦǤǡ
Ǥ
Ǥ
ȋ ȌǤ
ͺȌ Ǥ
Ǥ
ͻȌ ǡ
Ǥ
ͳͲȌ
Ǥ
Ǥ
ͳͳȌ Ǥ
Ǥ
ǮǯǤ
ͳʹȌ
6 |
ȋ ǡǡ
ǦͺǦͳȀʹdz ȌǤǦȋȌ
Ǥ
ͳ͵Ȍ ǡͲͲͲǯͺͻͺǯǤ
Ǥ
ͳͶȌ ͷ Ǥ
ͳͳǤͷǡ
ͳʹǤͷǤ
ȋȌ Ǥ
ͳͷȌ Ǧ
ͳʹ Ǥ
ȋ
Ȍǡ ǡ
ͶͻǤ
ǦǤ
ͳȌ Ͷǡ Ͷͻ
Ǥ
ͳȌ ǦǯǤ
Ǥ
ͳͺȌ ǡ
ǡ Ǥǡ
Ǥ
Ǥ
ͳͻȌ
ͳʹǯǤ
ǯǤ
ǡ
ǤǤ
ʹͲȌ Ǧ
͓ʹȋ ͳƬʹȌǤ ǡ
ͳͲͲͲǡ
ǦǤ ǡ
ͷǡ ͺͷͲȋ
ȌǤ
ʹͳȌ Ǥǯ
7 |
ǡȋȌ
Ǥ ͓ʹǤ
͓͵ ǡ
Ǥ
Ǥ
ʹʹȌ
Ǥ
ʹ͵Ȍ Ǥ
Ǥ ǦǤ
Summary
ǡǤ
ȋͺȀͳͺȌǮǯǡ
ǡ ǡǤ Ǥ
ǡ ǡ
Ǥ ͳͳǤͷ
ǡ
ͳʹǡ Ǥ
ǡ Ǥ ǡ ǡ
͵ Ǥǡ
ǡ
ȋ ȌǤ ǡ
ǡ Ǥ
ǡ
Ǥ
ǡ
Ǥ
ǡ Ǥ ǡ
ǡ
Ǥ
ǡ ǣ
ͳȌ Ǥ
Ǥ
ʹȌ Ǥ
͵Ȍ Ǥ
ͶȌ Ȁ Ǥ
ͷȌ ǡͲͲͳǯǤ
Ȍ Ǥ
Ȍ Ǥ
ͺȌ Ƭ ǣ
8 |
Ȍ
Ȍ
Ȍ Ǧ
Ǧǡ
Ǥ
ǡ
Ǥ
____________________________ ________________________
ͻͷͲ ʹͲͲ
ǡͲʹͶ
ǣͷͳʹͷͲǦͷ͵
ǣgbeck@endeavormgmt.com
9 |
Appendix A – CV of Frederick E. Beck
Frederick E. Beck
EDUCATION
Ph.D., Petroleum Engineering, Louisiana State University, Baton Rouge, La.,1986
M.S., Petroleum Engineering, Louisiana State University, Baton Rouge, La.,1984
B.S., Geology, Louisiana State University, Baton Rouge, La.,1981
PROFESSIONAL ACTIVITIES AND HONORS
Member, LSU Petroleum Engineering Industry Advisory Committee, since 1998, Chairman 2001
Member, Society of Petroleum Engineers, since 1981. SPE Distinguished Lecturer 1995-96. ATCE Drilling Program
Committee 2009, 2010, 2011, 2012; HPHT Operations Reprint Committee, 2009-2010
Member, International Association of Drilling Contractors, 1997-2002, Program Committee, SPE/IADC Drilling
Conference, 2000-2002
Exceptional Contribution Award, 1996, Arco Alaska, Inc., for development of short radius drilling techniques in
Prudhoe Bay, Alaska.
Exceptional Contribution Award, 1994, Arco Alaska, Inc., for development of medium radius drilling techniques in
Prudhoe Bay, Alaska.
Recipient, Outstanding Teaching Award, 1990, New Mexico Tech.
Member, American Association of Petroleum Geologists, 1980-90.
Recipient, Petroleum Engineering Department Award for Excellence in Teaching, 2010, 2011
EMPLOYMENT SUMMARY
Strategic Operations Advisor, Rockport Energy Solutions, January 2024 - present
Senior Advisor, Endeavor Management Energy Advisory Group, December 2019- present
Drilling Manager, Asset Manager, Senior Vice President, Statoil, December 2012 – May 2018
x Bakken Drilling Manager 2012-2014
x Bakken Asset Manager 2014-2015
x Senior Vice President U.S. Onshore 2015-2018
Drilling Consultant, Brigham Oil and Gas, Statoil and Halliburton June 2011 – April 2013
x Expert witness in BP Macondo case (personal reference via Gavin Hill, Dykema, 214-244-9584)
Associate Professor and Stephen A. Holditch Faculty Fellow, Department of Petroleum Engineering, Texas A&M
University, September 2009-2012
x Taught Courses in Drilling Engineering at both Undergraduate and Graduate level
x Directed research activities of 1 PhD and 7 M.S. Students
x Generated funded research in the areas of HPHT Cementing and HPHT Gas Solubility
10 |
Vice President, Drilling /Operations, Gastar Exploration, Ltd, April 2002-April 2011
x Responsible for drilling and completion engineering and operations supervision
x Performed engineering, planning, and operations supervision on
o over 30 wells during this period, with depths from 13,000-20,000’, all wells HPHT.
o horizontal wells at vertical depths greater than 13,000’ and temperatures over 300ºF.
o vertical wells with depths from 16,500’-20,000’ and temperatures in excess of 400º F and formation
pressures in excess of 17,000 psi.
o HTHP fracture stimulations
x Managed all related contracts for goods and services
Consultant, 1994-2006
x Provided expert witness consultation to law firms
x Developed Extended Reach and Horizontal Drilling Short Course, presented at the Chevron Training Center
1997-2006
x Edited and compiled Extended Reach and Horizontal Drilling Manual for the Chevron Drilling Training
Alliance
x Developed Horizontal Drilling Short Course, presented through Murchison Drilling Schools worldwide, 1994-
1997
Vice President, Nabors Drilling USA, Inc., June 1997 – February, 2002
x Managed all turnkey drilling operations in Nabors Drilling, USA
x Developed methods for successfully drilling depleted formations in geopressured sections
x Led NDUSA in safety performance for two years, with 1 year with no OSHA Recordable accidents
x Developed and implemented company wide well control project
x Developed and implemented company wide drilling policies
x Negotiated and managed third party performance contracts
x Provided engineering support for Nabors' footage contract drilling operations
x Performed general Staff Engineering services
Drilling Consultant, Nabors Alaska Drilling, Inc., March 1996-June 1997
x Provided contract rig site supervision of BP Exploration North Slope rig operations.
x Provided drillstring design, engineering, and rig site supervision for the world’s first slim-hole re-entry
horizontal well to utilize drillpipe inside production tubing (now known as TTRD).
x Performed process review of Nabors’ Rocky Mountain footage operations.
x Provided trouble shooting for Nabors Drilling, USA south Louisiana and southeast Texas turnkey wells.
x Solved severe drillstring failure problems in West Texas.
Drilling Engineer/Rig Supervisor, ARCO Alaska, Inc., 1990-1996
x Responsible for planning and supervision of rig operations.
x Lead engineer for horizontal wells in the Prudhoe Bay Unit
x Lead engineer for extended reach equity determination wells in the Pt. McIntyre development
x Extensive field supervisory experience includes
o extended reach drilling
o horizontal drilling - long, medium, and short radius, and multilateral wells
o re-entry redrills - conventional and horizontal wells
o workovers
o completions, including multilateral horizontal, cemented horizontal, and drillpipe conveyed
underbalanced perforating on horizontal wells.
o hydraulic fracture stimulations
x Significant accomplishments include
o designed the first medium radius horizontal well in Prudhoe Bay
o supervised the first short radius horizontal well in Prudhoe Bay
o planned and supervised the first horizontal well to execute a planned (47°) azimuth change
o supervised operations for over two continuous years with no lost time accidents or spills
o supervised drillpipe conveyed underbalanced perforation operations utilizing over 2000’ of guns in a
single run.
11 |
Assistant Professor, New Mexico Tech, Socorro, NM, 1987-1990
x Taught undergraduate and graduate courses covering drilling, well completions, logging, reservoir stimulation,
reservoir engineering, and production engineering.
x Generated over $130K of funded research projects in the areas of drilling fluids technology and waste
remediation.
Consultant, ARCO Oil and Gas, Plano, Texas, 1988-1990
x Research in well control and drilling hydraulics.
Post Doctoral Researcher, Louisiana State University, Baton Rouge, La.,1987
x Well control research.
Teaching/ Research Assistant, Louisiana State University, Baton Rouge, La., 1981-1986
x Taught "Subsurface Geology for Petroleum Engineers".
x Conducted MMS funded research project on well control.
Reservoir Engineer, Tenneco Oil Co., Lafayette, La., 1983
x Correlated well log parameters to production rates for offshore gas wells.
Geologist, Louisiana Land and Exploration Co., New Orleans, La., 1981
x Subsurface mapping, prospect generation.
Engineering Technician, Meurer, Serafini, and Meurer, New Orleans, La., 1980
x Surveying of corehole locations in proposed lignite mine
PUBLICATIONS AND REPORTS
"Experimental and Theoretical Considerations for Diverter Evaluation and Design", by F.E. Beck, J.P. Langlinais, and
A.T. Bourgoyne, Jr., SPE 15111, presented at the California Regional Meeting, Society of Petroleum Engineers,
Oakland, CA, April 3-5, 1986. Accepted for publication in 1988 by the SPE.
"An Analysis of the Design Loads Placed on a Well by a Diverter System", by F.E. Beck, J.P. Langlinais, and A.T.
Bourgoyne, Jr., SPE 16129, presented at the SPE/IADC Drilling Conference, New Orleans, LA., March 15-18, 1987.
Accepted for publication in 1988 by the SPE.
"A Method for Determining the Feasibility of Dynamic Kill of Shallow Gas Flows", by W.L. Koederitz, F.E. Beck, J.P.
Langlinais, and A.T. Bourgoyne, Jr., SPE 16691, presented at the 62nd Annual Technical Conference, Dallas, TX,
September 27-30, 1987.
"A Method for Determination of Permeability, Skin, and Turbulence Factor from an Open-Flow Potential Test", by F.E.
Beck and R.L. Lee, SPE 18270, presented at the 63rd Annual Technical Conference and Exhibition, Houston, TX,
October 2-5, 1988.
"Reservoir and Geologic Study of Sulimar Queen Field, New Mexico", by T. Cowen, F. Beck, and J. McMillan, internal
report, Petroleum Recovery Research Center, New Mexico Tech, Socorro, NM, 1989.
"Report of Thermal Spallation Drilling Progress", by F.E. Beck, R.E. Williams, and R.H. Potter, for Los Alamos
National Labs, NM, 1989.
"Computer Simulation of a Reverse Circulation Well Control Procedure for Gas Kicks", by S. Miska, F.E. Beck, and
B.S. Murugappan, SPE Drilling Engineering, December 1992. (SPE 21966), originally prepared for the SPE/IADC
Drilling Conference, Amsterdam, March 11-14, 1991.
"Improved Performance of Prudhoe Bay Horizontal Completions", by F. E. Beck, T. Stagg, and G.R. Atol, presented at
the World Oil 4th International Conference on Horizontal Well Technology, Houston, 1992.
"A Clarified Xanthan Drill-in Fluid for Prudhoe Bay Horizontal Wells", by F.E. Beck, J.W. Powell, and M. Zamora, SPE
25767, presented at the SPE/IADC Drilling Conference, Amsterdam, February 22-25, 1993.
12 |
"The Effect of Rheology on Rate of Penetration", by F.E. Beck, J.W. Powell, and M. Zamora, SPE 29368, presented at
the SPE/IADC Drilling Conference, Amsterdam, March, 1995.
"Rheology Design to Optimize Rate of Penetration", by E.E. Maidla, A.J. Reay, F.E. Beck, and C.P. Tan, SPE 35062,
presented at the SPE/IADC Drilling Conference, New Orleans, March 1996.
“Finite Element Analysis Couples Casing and Cement Designs for HTHP Wells in East Texas”, by James Heathman and
F.E. Beck, SPE 98869, presented at the IADC/SPE Drilling Conference, Miami, FL, February 2006.
“Intermediate Casing Collapse Induced by Casing Wear in High-Temperature and High-Pressure Wells”, by Z. Shen and
F.E. Beck, SPE 155973, presented at the SPE International Production and Operations Conference and Exhibition, Doha,
Qatar, May 2012.
“Three Dimensional Modeling of Casing and Cement Sheath Behavior in Layered, Non-Homogeneous Formations”, by
Z. Shen and F.E. Beck, SPE 156469, presented at the SPE/IADC Asia Pacific Drilling Conference, Tianjin, China, July
2012.
“Thermoporoelastic Effects of Drilling Fluid Temperature on Rock Drillability at the Bit/Formation Interface”, by
Kritatee Thepchatri and F.E. Beck, Paper ID No. 213, to be presented at the 47th US Rock Mechanics / Geomechanics
Symposium, San Francisco, CA, USA, June 2013
EXPERT WITNESS CASE LOG
2023 – Triad Energy v Tres Management, District Court, Oklahoma County, OK Case No. CJ-2020-4116
(Operational dispute, drilling operations, report, deposition, and trial testimony)
2021 – Hill v Halliburton, et al, 18th Judicial District Court, West Baton Rouge Parish, LA Case No. 4125 Div B
(Subsurface trespass by hydraulic fracture, report only)
2021 – Red Rocks Resources v C&J Spec Services, U.S. District Court, Western District OK, Case No. CIV-19-0851-HE
(operational dispute concerning cementing operations, report and deposition)
2018 - Wise v Dallas-Morris Drilling et al, U.S. District Court, Colorado, Case No. 17-cv-01676-MEH
(Drilling equipment operations and maintenance, report only)
2011 -2013 - BP v Transocean, Halliburton et al, U.S. District Court, Eastern District LA. Case 2:10-cv-02771, MDL #2179
Sec J (well design, control, drilling, and monitoring regarding the Deepwater Horizon blowout and oil spill, report, rebuttal
report, deposition, trial testimony)
2011? – City of Houston v ?, deposition and trial testimony, directional drilling capabilities
2002? – Nabors v ?, deposition and trial testimony, blowout in Mississippi
1991 – Ocean Odyssey wrongful death inquiry, inquiry testimony, general engineering principles
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
October 2, 2023
Certified Mail
Return Receipt Requested
7018 0680 0002 2052 9587
Mr. Monte Myers
Drilling Manager
Hilcorp Alaska LLC
P.O. Box 244027
Anchorage, AK 99524-4027
Re: Notice of Investigation
Well Control Event – Enterprise Rig 151
North Cook Inlet Unit A-18 Well (PTD 2230330)
Dear Mr. Myers:
The Alaska Oil and Gas Conservation Commission (AOGCC) has initiated an investigation of the
well control event while drilling the North Cook Inlet Unit A-18 well with Enterprise Rig 151.
The incident reportedly occurred on August 18, 2023, at approximately 5:00 pm. Hilcorp Alaska
LLC (Hilcorp) provided BOPE Usage Reports on August 19, 2023, and August 21, 2023, in
accordance with 20 AAC 25.035(e)(11) and Industry Guidance Bulletin 10-003A. Hilcorp also
provided an overview of the event to AOGCC staff on August 31, 2023, at the AOGCC’s request.
The AOGCC is currently seeking an independent 3rd party to review the well control event
including the actions leading up to and including the procedures to regain well control.
Recommended actions to prevent recurrence would be developed as part of the 3rd party review.
Hilcorp is requested to provide a single-point-of-contact for technical matters during this
investigation. Information requests and interviews may be necessary as the investigation
progresses.
Hilcorp must preserve all documents which relate in any way to the well control event, including
computer records and those documents which might otherwise be destroyed in the normal course
of business or during the response to this incident, for inspection and production by the AOGCC.
The AOGCC reserves the right to pursue enforcement action in connection with the well control
event as provided by 20 AAC 25.535. Should you have any questions about this information
request, please contact Bryan McLellan at 793-1226.
Docket Number: OTH-23-027
NCIU A-18 Well Control Event
October 2, 2023
Page 2 of 2
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
cc: P. Sherry (DOL)
B. McLellan
J. Regg
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.10.02
12:32:43 -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: 4/4/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240404
Well API #PTD #Log Date Log Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF
BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf
HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT
KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF
KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF
KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF
END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF
MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey
MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter
MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL
NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf
NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf
PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT
PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF
PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF
PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF
PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF
SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF
SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf
Please include current contact information if different from above
T38683
T38684
T38685
T38686
T38689
T38687
T38690
T38691
T38691T38692
T38963
T38963
T38694
T38694
T38694
T38695
T38696
T38697
T38698
NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf
NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.09 13:48:29 -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: 3/19/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240319
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 13 50133205250000 203138 12/5/2023 AK E-LINE Plug/Cement/Cutter
GP ST 18742 37 (AN
37) 50733203940000 187109 11/12/2023 AK E-LINE PERF
IRU 241-01 50283201840000 221076 2/25/2024 AK E-LINE Perf/GPT
KU 13-06A 50133207160000 223112 2/9/2024 AK E-LINE GPT
MPU CFP-02 50029212580000 184242 3/13/2024 READ CaliperSurvey
NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf
PBU L-122 50029231470000 203051 3/2/2024 AK E-LINE LowerPatchPacker
PBU L4-14 50029219730000 189098 11/22/2023 AK E-LINE PERF
SRU 241-33B 50133206960000 221053 3/4/2024 AK E-LINE GPT/Cmnt/CIBP/Perf
Please include current contact information if different from above.
T38648
T38649
T38650
T38651
T38652
T38653
T38654
T38655
T38656
NCIU A-18 50883201890000 223033 12/13/2023 AK E-LINE GPT/Plug/Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.21 11:50:20 -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: 3/14/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240314
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 13 50133205250000 203138 1/20/2024 AK E-LINE GPT/PL
BCU 13 50133205250000 203138 1/4/2023 AK E-LINE JetCut/CBL
BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf
HV B-13 50231200320000 207151 12/22/2023 AK E-LINE CBL
IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf
KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf
KTU 32-07H 50133205110000 202043 10/27/2023 AK E-LINE PPROF
KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL
KU 21X-32 50133202040000 169100 12/8/2023 AK E-LINE JetCut
MPU CFP-02 50029212580000 184242 3/9/2024 READ CaliperSurvey
NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT
NIA NK-18 50029224210000 193177 12/13/2023 AK E-LINE IPROF
PTM P1-13 50029223720000 193074 12/9/2023 AK E-LINE Cement
TBU M-11 50733205900000 210145 1/8/2024 AK E-LINE Perf
TBU M-15 50733204220000 190109 2/7/2024 AK E-LINE GPT/Perf
Please include current contact information if different from above.
T38615
T38615
T38616
T38617
T38618
T38619
T38620
T38621
T38622
T38623
T38624
T38625
T38626
T38627
T38628
NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.15 11:38:35 -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: 12/21/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231221
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
MPU B-28 50029235660000 216027 12/6/2023 HALLIBURTON PATCH
MPU F-10A 50029226790100 223027 12/7/2023 HALLIBURTON PLUG
MPU F-10A 50029226790100 223027 12/7/2023 HALLIBURTON TUBING-PUNCH
NCIU A-12B 50883200320200 223053 12/1/2023 HALLIBURTON RBT
NCIU A-18 50883201890000 223033 12/4/2023 HALLIBURTON RBT
PBU 01-28B 50029215970200 223089 12/13/2023 HALLIBURTON RBT
Please include current contact information if different from above.
T38238
T38239
T38239
T38240
T38241
T38242
12/22/2023
NCIU A-18 50883201890000 223033 12/4/2023 HALLIBURTON RBT
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.22
09:09:45 -09'00'
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:McLellan, Bryan J (OGC)
To:Ryan Rupert
Cc:Juanita Lovett; Karson Kozub; Dan Marlowe
Subject:RE: NCIU A-12B CBL (PTD #223-033)
Date:Tuesday, December 5, 2023 12:22:00 PM
Ryan,
Hilcorp has approval to perforate per sundry 323-604.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Tuesday, December 5, 2023 8:40 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Juanita Lovett <jlovett@hilcorp.com>; Karson Kozub <kkozub@hilcorp.com>; Dan Marlowe
<dmarlowe@hilcorp.com>
Subject: NCIU A-12B CBL (PTD #223-033)
Bryan-
Here’s the CBL for NCIU A-18. Please let us know if we have approval to perforate per attached
sundry.
A-12B will be the first well perforated (as early as tomorrow, Wed 12/6), so that one is the priority.
Thanks,
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, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1
Regg, James B (OGC)
From:Regg, James B (OGC)
Sent:Wednesday, November 22, 2023 12:17 PM
To:Ryan Rupert
Cc:Harold Soule - (C); Juanita Lovett; Dan Marlowe; McLellan, Bryan J (OGC)
Subject:RE: Tyonek post-drill CT work
Attachments:Hilcorp Kenai Service CTU BOPE Test frequency 1-2021 final.pdf
AOGCC approves Hilcorp’s request to test SLB CT1 BOPE weekly instead of on each well for NCIU “Tyonek” wells A‐12B
(PTD 2230530), A‐17 (PTD 2230310) and A‐18 (PTD 2230330). Our approval applies only to this parƟcular request based
on the jusƟficaƟon provided (SLB CTU; all wells on same leg; 3‐well campaign). TesƟng specifics are to be as outlined in
the 1/25/2021 leƩer that addresses an alternate test interval for service coil tubing BOPE.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907‐793‐1236
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Wednesday, November 22, 2023 10:24 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>
Cc: Harold Soule ‐ (C) <hsoule@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe
<dmarlowe@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Rupert
<Ryan.Rupert@hilcorp.com>
Subject: Tyonek post‐drill CT work
Mr. Regg‐
We have 3 new drill wells all located on Leg #1 of the Tyonek Plaƞorm. The jack‐up rig skidded back yesterday, and we
anƟcipate starƟng CT operaƟons as soon as Thu 11/23. (Harold has already put in the 48hr noƟficaƟon for BOP
test). The work will be executed campaign style unƟl all 3 wells CT scopes have been completed.. Given that the work
will be performed by Schlumberger, and all 3 wells are on the same leg, Hilcorp would like to request a variance to the
BOP tesƟng requirements. Hilcorp requests to test CT BOP’s weekly instead of on each well for this campaign. Please
advise if this is acceptable. Thank you.
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
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.
N. Cook Inlet Unit A-18PTD 2230330
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):
10,117 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
CO 68A
11/20/2023
4-1/2"
LTP & SSSV 4,639 (MD) 3,093 (TVD) & 459 (MD) 459 (TVD)
10,088'
Perforation Depth MD (ft):
±7,371 -±10,000 (proposed)
5,449'
±4,514 -±7,006 (proposed)
7,094'4-1/2"
30"
9-5/8"
384'
5,430'
MD
1,630psi
6,870psi
384'
3,461'
384'
5,430'
Length Size
Proposed Pools:
12.6
TVD Burst
4,684
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-033
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20189-00-00
Hilcorp Alaska, LLC
Other: CT Operations / N2
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
N Cook Inlet Unit A-18
N Cook Inlet N/A Tertiary System Gas
7,122 10,006 7,012 2,943psi N/A
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 8:14 am, Nov 07, 2023
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2023.11.06 16:33:19 -
09'00'
Dan Marlowe
(1267)
323-604
4875' - bjm
Perforate New Pool
CT BOP test to 3500 psi. Approval granted for weekly CT BOP test for 3-well campaign on Tyonek.
Submit CBL to AOGCC and obtain approval before perforating
SFD 11/16/2023 DSR-11/15/23
X
3202'4875'
Yes, for CT work 11/21/23
Bryan McLellan
10-407
BJM 11/27/23
*&:JLC 11/27/2023
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.11.27 15:26:27
-09'00'
RBDMS JSB 112823
Initial Completion
Well: NCIU A-18
Well Name:NCIU A-18 API Number:50-883-20189-00-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-033
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,643 psi @ 7,006’ TVD 0.52psi/ft to deepest perf
Max. Potential Surface Pressure: 2943 psi Using 0.1 psi/ft
Brief Well Summary
Spartan 151 has successfully drilled and cased Tyonek well A-18 as part of the 2023 drilling campaign. Once
complete with the 3rd drill well on this leg, the jackup rig will leave the platform, and all 3 wells (A-17, A-18, A-
12B) will be ready for post-rig completion. The post-rig work will be executed campaign style. All proposed
perforations below are within the Tertiary System Gas Pool.
The goal of this project is to complete the well after the drilling rig leaves.
Pertinent wellbore information:
- TRSSSV installed
-DGLV’s currently
- Fluids form 10/1/23
o Rig displaced 4-1/2” liner wiper plug with 10.3ppg mud
o Upper completion tubing and IA circ’d to FIW
- MIT’s on 10/2/23
o 4-1/2” liner, LTP, and 9-5/8” casing passed a 2000psi MIT
o MIT-IA passed to 3000psi
o MIT-T passed to 3500psi
Pre-sundry
1. MIRU SL
2. PT to 250 low / 3500 high
3. Install live GLV’s
4. Drift to PBTD
5. RDMO SL
All proposed
perforations below are within the Tertiary System Gas Pool.
Initial Completion
Well: NCIU A-18
Coiled Tubing Procedure
1. MIRU Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high if necessary
a. SLB Coiled Tubing
b. Weekly BOP test requirement
c. All 3 wells of this CT campaign are on same leg
3. MU cleanout BHA
4. RIH to PBTD and swap well over to water
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. Target recovery = 398bbls
i. IA Volume: 245bbls
ii. Tubing Volume: 71bbls
iii. Liner volume: 81 bbls
c. Want to evacuate IA fluid through live GLV’s as well
7. RDMO CT
Beluga E-Line Perf procedure
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high
3. Ensure CBL approval from AOGCC before perforating
4. RIH and perforate Beluga gas sands from ±7,371 - ±10,000’ MD (±4,514’ - ±7,006’ TVD) per RE/Geo
5. RDMO EL
CONTINGENCY: (if any zone makes unwanted solids or water)
1. RU nitrogen to tubing and PT lines to 4000psi
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 / 3500psi high
5. Set 4-1/2” CIBP or patch per OE
6. RDMO Nitrogen and EL
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. CT BOP Drawing
4. Nitrogen procedure
±7,371 - ±10,000’ MD (±4,514’ - ±7,006’ TVD)
_____________________________________________________________________________________
Updated By: JLL 11/3/2023
SCHEMATIC
North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD = 10,006’ MD / 7,012’ TVD
TD = 10,117’ MD / 7,122’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
PB 1
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 5,430’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ SSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2” Est. TOC @ TOL (40% excess) L – 734 sx / T – 370 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’ Dummy
2 4,573’ 3,062’ Dummy
NOTE
7,312’ RA Marker
8,438’ RA Marker
Superseded
_____________________________________________________________________________________
Updated By: JLL 11/3/2023
PROPOSED
North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD = 10,006’ MD / 7,012’ TVD
TD = 10,117’ MD / 7,122’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
PB 1
4-1/2”
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 5,430’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ SSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2” Est. TOC @ TOL (40% excess) L – 734 sx / T – 370 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±7,371 ±10,000 ±4,514 ±7,006 ±2,629 Future Proposed
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’ Dummy
2 4,573’ 3,062’ Dummy
NOTE
7,312’ RA Marker
8,438’ RA Marker
Superseded
SLB Stack Drawing
Not Drawn To Scale--- For Reference Only
2 1/16 10M
Flanged
Plug Valve
(Manual)
from KP
Well Floor
HR 580 Injector Head with 72" Gooseneck
4.06" 10K Conventional Stripper – 1.75"
C062 Pin Connection
Manual
2 1/16 10M
Provided by client
Blind/Shear
Pipe/Slip
4 1/16 10M
Combi BOP
Lubricator to
Injector Head
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: 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
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From:Regg, James B (OGC)
To:Ryan Rupert
Cc:Harold Soule - (C); Juanita Lovett; Dan Marlowe; McLellan, Bryan J (OGC)
Subject:RE: Tyonek post-drill CT work
Date:Wednesday, November 22, 2023 12:17:56 PM
Attachments:Hilcorp Kenai Service CTU BOPE Test frequency 1-2021 final.pdf
AOGCC approves Hilcorp’s request to test SLB CT1 BOPE weekly instead of on each well for NCIU
“Tyonek” wells A-12B (PTD 2230530), A-17 (PTD 2230310) and A-18 (PTD 2230330). Our approval
applies only to this particular request based on the justification provided (SLB CTU; all wells on same
leg; 3-well campaign). Testing specifics are to be as outlined in the 1/25/2021 letter that addresses
an alternate test interval for service coil tubing BOPE.
Jim Regg
Supervisor, Inspections
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907-793-1236
From: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Sent: Wednesday, November 22, 2023 10:24 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>
Cc: Harold Soule - (C) <hsoule@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe
<dmarlowe@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Rupert
<Ryan.Rupert@hilcorp.com>
Subject: Tyonek post-drill CT work
Mr. Regg-
We have 3 new drill wells all located on Leg #1 of the Tyonek Platform. The jack-up rig skidded back
yesterday, and we anticipate starting CT operations as soon as Thu 11/23. (Harold has already put in
the 48hr notification for BOP test). The work will be executed campaign style until all 3 wells CT
scopes have been completed.. Given that the work will be performed by Schlumberger, and all 3
wells are on the same leg, Hilcorp would like to request a variance to the BOP testing requirements.
Hilcorp requests to test CT BOP’s weekly instead of on each well for this campaign. Please advise
if this is acceptable. Thank you.
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 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.
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From:Ryan Rupert
To:McLellan, Bryan J (OGC)
Cc:Juanita Lovett; Dan Marlowe; Harold Soule - (C); Ryan Rupert
Subject:NCIU A-18 (PTD #223-033) and A-12B (PTD#223-053)
Date:Tuesday, November 21, 2023 3:16:11 PM
Attachments:10-403 NCIU A-12B PTD 223-053.pdf
10-403 NCIU A-18 PTD 223-033.pdf
Bryan-
Just wanted to document our phone conversation including verbal approval for the CT portions of
The NCIU A-18 and A-12B sundries (attached). We’ll be rigging up CT this weekend. Thank you.
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 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.
_____________________________________________________________________________________
Updated By: JLL 11/22/23
PROPOSED
North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD = 10,006’ MD / 7,012’ TVD
TD = 10,117’ MD / 7,122’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
TOW
4,875’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,875’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ Giant Oil Tools - TR-SCSSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2” Est. TOC @ TOL (40% excess) L – 734 sx / T – 370 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±7,371 ±10,000 ±4,514 ±7,006 ±2,629 Future Proposed
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’ Dummy
2 4,573’ 3,062’ Dummy
NOTE
7,312’ RA Marker
8,438’ RA Marker
_____________________________________________________________________________________
Updated By: JLL 11/22/23
SCHEMATIC
North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
PBTD = 10,006’ MD / 7,012’ TVD
TD = 10,117’ MD / 7,122’ TVD
4/5
1
2
3
RKB = 126.6’
X
30”
12-1/4”
hole
9-5/8”
8-1/2”
hole
4-1/2”
TOW
4,875’
PB1
Radioactive
BHA - TOF
5,377’
Cement
Retainer @
5,009’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor – Driven
to Set Depth -- Weld 29”Surf384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 4,875’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 4,639’ 10,088’
4-1/2" Prod Tieback 12.6 L-80 Hyd 533 3.958” Surf 4,684’
JEWELRY DETAIL
No.Depth
(MD)
Depth
(TVD)Item
1 459’ 459’ Giant Oil Tools - TR-SCSSSV
2 1,006’ 996’ ES Cementer
3 4,626’ 3,087’ X nipple 3.813” Profile
4 4,639’ 3,093’ Liner hanger / LTP Assembly
5 4,684’ 3,114’ Seal Stem
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 – 955 sx Stg 2 1070 sx
4-1/2” Est. TOC @ TOL (40% excess) L – 734 sx / T – 370 sx
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 2,360’ 1,991’ Dummy
2 4,573’ 3,062’ Dummy
NOTE
7,312’ RA Marker
8,438’ RA Marker
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: 10/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-18 + PB1
PTD: 223-033
API: 50-883-20189-00-00 (NCIU A-18)
API: 50-883-20189-70-00 (NCIU A-18PB1)
FINAL LWD FORMATION EVALUATION LOGS (08/05/2022 to 08/13/2022)
x ROP, DGR, SLIM EWR-4, ALD, CTN, PCG (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Data Main Folders:
SFTP Transfer - Data Sub-Folders:
Please include current contact information if different from above.
PTD: 223-033
NCIU A-18: T38057
NCIU A-18 PB1: T38058
10/13/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.10.13
13:51:19 -08'00'
Global Radiation Safety 3000 N. Sam Houston Parkway East · Plaza 1, Office 5320M
Houston, Texas 77032-3219
September 19, 2023
U.S. Nuclear Regulatory Commission – Region IV
1600 East Lamar Blvd.
Arlington, TX 76011
Attn: Division Director - DNMS
Re: Notification of Well Logging Sealed Source Abandonment
Halliburton Energy Services, Inc.
USNRC License No. 42-01068-07 Amendment No. 86
This letter comprises the required 30-day written notification of source abandonment as required
by 10 CFR 39.77(d). This is a follow-up to the communications between Halliburton and NRC
Region IV in which permission to proceed with the abandonment was granted on August 26,
2023.
Date of Occurrence:
Company Name:
Well Name & Registration No.:
Well Location:
Rig Name:
19 – August - 2023
HilCorp Alaska, LLC
3800 Center Point Dr.
Suite 1400
Anchorage, AK 99503
NCI A-18PB1 / 50-883-20189-70-00
Lat. 61° 4’ 36.4" North
Long 150° 56' 55.5" West
Spartan Rig 151
Sources Abandoned: One 296GBq (8Ci) Am241Be doubly encapsulated
radioactive sealed source, solid, special form. Eckert &
Ziegler, Model LWD4133; Source Serial Number S10-
012 and One 74Gbq (2.0 Ci) Cs-137 doubly
encapsulated radioactive sealed source, solid, special
form. Eckert & Ziegler, Cs7.P07; Source Serial Number
EZ22102D
Immobilization method:
Brief Well Summary –
The A-18 production hole was drilled to a TD of 8986’.
The was shut in during a trip due to a swab kick. After
the well was dead the drilling BHA could not be moved.
Eline ran a string shot to back off the DP at 5377’.
There is a 1937’ fish than includes drill pipe, HWDP,
Drilling BHA with RA sources. Wireline made a cut at
6350’ and subsequent fishing attempts have been
unsuccessful. The plan forward is to abandon the BHA
with cement and sidetrack.
Run 9-5/8” cement retainer to 5000’, Squeeze 40 bbls of
cement below the retainer. Lay in 7.3bbls of 15.8#
cement plug on top of retainer (100’ of cement)
a. TOF 5377’
9/19/2023 Notification of Source Abandonment USNRC License No. 42-01068-07
Page 2 of 3
Results of Efforts to Immobilize and
set sources in place:
Depth of Well:
Depth of Bottom of Fish:
Depth of Sources:
Depth of Top of Fish:
Depth of Bottom of Cement Plug:
Depth of Top of Cement Plug:
b. Upper source – 7236’ (the DP, HWDP,
and flex joints will be considered a
mechanical deflection device)
c. Include red dye in cement
d. Target TOC 4900’
Run 9-5/8” whipstock and set at 4870’, Mill Window,
Obtain new FIT, Sidetrack with 8.5” directional drilling
assembly.
Abandonment procedure successfully completed on
27 – August - 2023
8986 ft. MD / 5989.7 ft. TVD
7313 ft. MD / 4464.9 ft. TVD
Am241Be source located at 7245 ft. MD / 4416 ft TVD
Cs-137 source located at 7230 ft. MD / 4405.4 ft. TVD
5377 ft. MD / 3439 ft. TVD
5848 ft. MD / 3666.5 ft. TVD
4905 ft. MD / 3216.3 ft. TVD
Description of Recovery Attempts:
Bit depth 7313' MD. Top of fish 5370' MD. Hole
Inclination 61.05° 8/24 - Screw in to fish and begin
jarring. No tool movement. Attempt to run radial cutter to
6028' MD to cut and retrieve drill pipe and get jars closer
to tools. Cutter could not get past jars. 8/25 - Add sinker
bars on to cutter to attempt to get it past jars. No
success so pulling out of hole to free point and
determine plan forward. Tentative plan is to recover
fishing BHA and request approval to abandon. Waiting
on abandonment proposal from client.
Warning Plaque:
See Attachment 1 for a representation of the plaque.
Attached Supporting Documents
Hilcorp Alaska. LL Abandon Sources / Sidetrack plan
Halliburton BHA Tally Well Information
Radiation Source Sealed Source Certificates
Radiation Source Leak Tests
Sincerely,
Kevin Bowery
Sr. Radiation Safety Officer – NAL / GOM
Halliburton Energy Services, Inc.
Email: Kevin.Bowery@Halliburton.com
9/19/2023 Notification of Source Abandonment USNRC License No. 42-01068-07
Page 3 of 3
Attachment: (1) Representation of Warning Plaque
ATTACHMENT 1
Representation of Permanent Warning Plaque
Well Name: NCI A-18PB1
Well Registration No. 50-883-20189-70-00
CAUTION
ONE 296 GBq (8 Ci) AM-241BE RADIOACTIVE SOURCE
AND ONE 74 GBq (2 Ci) CS-137 RADIOACTIVE
SOURCE ABANDONED August 27, 2023. FIRST
SOURCE LOCATED AT 7230 FT. MD. 4405.4 FT. TVD
AND SECOND SOURCE LOCATED AT 7245 FT. MD.
4416 FT TVD. PLUG BACK DEPTH TOP OF CEMENT
PLUG 4905 FT. MD & 3216.3 TVD.
AVOID BORE BELOW PLUGBACK AND DO NOT RE-
ENTER THIS WELL BELOW PLUG BACK BEFORE
CONTACTING THE NUCLEAR REGULATORY
COMMISSION.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________N COOK INLET UNIT A-18
JBR 10/20/2023
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:0
Initially had trouble getting all the air out of everything for a solid shell test.Went ahead and tested all H2S and Gas meters at
this time. 7 stations active and all passed.Tested all rams with 4.5" test joint. Very good test overall.
Test Results
TEST DATA
Rig Rep:Anthony Boyd / Bruce Operator:Hilcorp Alaska, LLC Operator Rep:Steve Dambacher/ Chris Ye
Rig Owner/Rig No.:Enterprise 151 PTD#:2230330 DATE:9/13/2023
Type Operation:DRILL Annular:
250/3500Type Test:BIWKLY
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopJDH230915144256
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7
MASP:
2989
Sundry No:
323-489
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 P
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
16 PNo. Valves
1 PManual Chokes
2 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8 P
#1 Rams 1 4.5 X 7" 5M P
#2 Rams 1 Blind/shear P
#3 Rams 1 4.5 X 7" 5?M P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8 5M P
HCR Valves 2 3 1/8 5M P
Kill Line Valves 3 3 1/8 5M P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1950
200 PSI Attained P19
Full Pressure Attained P132
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
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P16
#1 Rams P12
#2 Rams P12
#3 Rams NA0
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P1
Sundry 323-489 - changed drilling plan (sidetrack around stuck/abandoned BHA)
Test charts attached
COMBUSTIBLE GAS DETECTION SYSTEM
Rig and Mud Pits - State Compliance Testing
FACILITY NAME:Tyonek Platform Rig 151
ROOM DESIGNATION:Rig, Shakers, Well Room
Instructions: Use this form to record combustible gas detector calibration data and alarm tests.
Cal Gas Cal Gas Verify
Gas-Free Applied Gas-Free Applied Sensativity Alarms at
Sensor Tag Name Faulted? Reading Reading Reading Reading With 50%20 and 40%
Or Location (%LEL) (%LEL) (%LEL) (%LEL)Gas Applied YES NO
Rig Gas Detectors
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
20 40 Yes
Sensativity
With 50%
Gas Applied YES NO
RIG H2S DETECTORS
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
10 20 Yes
Note:
Comb gas used 50% LEL
H2S gas used 25ppm
Conditions As LeftConditions As Found
Verify
Alarms at 10
Cal Gas Cal Gas
No
0
0
0
0
0
0
No
No 0
No
No
No
No
50%50%0
and 20 ppm
Gas-Free
Reading
Applied
Reading
Gas-Free
Reading
Applied
Reading
NOTES: All devices activated as they should, No Faults or Errors on system.
TECHNICIAN: Ian Hanna STATE INSPECTOR: Guy Cook/ Josh Hunt Date: 09/13/2023
(PPM)(PPM)(PPM)(PPM)
151 Rig Floor (Ch. 13)
Aux Wellbay Room (Ch. 14)
No
No
No
No
No 25 PPM
0 25 PPM
0
0
0
0
No 0
Aux Wellbay Room (Ch. 7)
151 Pits (Ch. 8)
Spare- Not in use (Ch.11)
151 Cellar (Ch.12)
151 Pits (Ch. 1)
151 Shakers (Ch. 3)
Spare-not in use (Ch. 4)
151 Cellar (Ch. 5)
151 Rig Floor (Ch.6)
151 Shakers (Ch.10)
151 Trip Tank (Ch. 2)
151 Trip Tank (Ch. 9)
25 PPM
25 PPM
25 PPM
25 PPM
25 PPM
0 25 PPM
0
0
0
0
0 25 PPM
No
0
25 PPM
25 PPM
25 PPM
Faulted?
25 PPM
50%
0
0
0
0
0
25 PPM
0
50%
50%
50%
50%
50%
50%0 50%
50%
50%
50%
50%
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 Other:
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?N/A
Yes No
9. Property Designation (Lease Number):10. Field:
North Cook Inlet Unit
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,986'N/A
Casing Collapse
Structural
Conductor
Surface 4750
Intermediate
Production
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:
Contact Email:
Contact Phone:
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
~4,736' (TOC Plug)~5,990'~3,135'2989 N/A
Tertiary System Gas Pool / Tertiary System Gas Pool
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):
N/A
Perforation Depth TVD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 17589 / ADL 37831
223-033
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20189-00-00
Hilcorp Alaska, LLC
NCIU A-18
Length Size
Proposed Pools:
N/A
TVD Burst
N/A
MD
6870
384'
3,465'
384'
5,430
30"
9-5/8"
384'
5,430'
Perforation Depth MD (ft):
N/A N/A
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
8/28/2023
N/A
N/A
m
n
P
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Drilling Manager
08/28/23
Monty M
Myers
By Grace Christianson at 3:11 pm, Aug 28, 2023
323-489
X
DSR-8/28/23
Lost circulation zones must be cured or isolated prior to penetrating the overpressured Beluga I interval.
SFD 8/28/2023
8/28/2023
BOP test to 3500 psi. Annular test to 2500 psi.
10-407
Change Approved Programm
BJM 8/30/23*&:
08/30/23
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.30 10:19:53
-08'00'
RBDMS JSB 030724
A-18 Drilling Program
Tyonek
Sean McLaughlin
Sidetrack Drilling Program
August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Contents
1. Well Summary...............................................................................................................................2
2. Management of Change Information............................................................................................3
3. Tubular Program...........................................................................................................................4
4. Drill Pipe Information...................................................................................................................4
5. Internal Reporting Requirements.................................................................................................5
6. Current Wellbore Schematic.........................................................................................................6
7. Planned Wellbore Schematic.........................................................................................................7
8. Drilling Summary..........................................................................................................................8
9. Mandatory Regulatory Compliance / Notifications......................................................................9
10. Preparatory Work and Mud Program........................................................................................11
11. Set Whipstock / Mill Window......................................................................................................12
12. Drill 8-1/2” Hole Section ..............................................................................................................13
13. Run 4-1/2” Production Liner.......................................................................................................14
14. Cement 4-1/2” Production Liner .................................................................................................18
15. Wellbore Clean Up & Displacement...........................................................................................20
16. Run Completion Assembly..........................................................................................................20
17. BOP Schematic............................................................................................................................22
18. Wellhead Schematic.....................................................................................................................23
19. Anticipated Drilling Hazards......................................................................................................24
20. FIT Procedure..............................................................................................................................25
21. Choke Manifold Schematic .........................................................................................................26
22. Casing Design Information..........................................................................................................28
23. 8-1/2” Hole Section MASP...........................................................................................................29
24. Directional Program (wp07) - Attached separately...................................................................30
Page 2 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
1. Well Summary
Well NCI A-18
Drilling Rig Rig 151
Leg & Slot Leg 1 / Slot 7
Directional plan wp05
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 10146’MD / 7116’TVD
AFE Number
AFE Days
AFE Drilling Amount
Work String 4.5” 16.6# S-135 CDS40
RKB –AMSL 126.6’
MSL to ML 73.3’
Well_Desc X_SPAK4_27 Y_SPAK4_27 X_SPAK4_83 Y_SPAK4_83 Location
NCI A-18_SHL 331999.46 2586732.89 1472024.77 2586494.58 1247' FNL, 980' FWL, Sec 6, T11N, R9W, SM, AK
NCI A-18_TPH 331099.18 2583356.73 1471124.33 2583118.53 644' FSL, 129' FWL, Sec 6, T11N, R9W, SM, AK
NCI A-18_BHL 330474.09 2580847.92 1470499.13 2580609.82 1874' FNL, 459' FEL, Sec 12, T11N, R10W, SM, AK
Page 3 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
2. Management of Change Information
Date: August 28, 2023
Subject: Changes to Approved Permit to Drill
File #: NCI A-18 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.
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
3. Tubular Program
Hole Section OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)Grade Conn Burst
(psi)
Collap
se
(psi)
Tension
(k-lbs)
Conductor
(previously
installed)
30”Assume
29”--Assume
158#X-56 Weld 1630 230
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 TXP 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)
Prod 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 16,176 10,959 468k
Page 5 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 Try to 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. Dennis LaRoche: C: (907) 513-7090
x Spills:
i. Keegan Fleming: C:907-350-9439
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 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
6. Current Wellbore Schematic
Page 7 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
7. Planned Wellbore Schematic
Page 8 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
8. Drilling Summary
A-18 is a 10,139’ MD / 7116’ TVD development gas well drilled from leg 1 slot #7 off the Tyonek platform.
The base plan is an infill wellbore to the Beluga U. The surface hole has been drilled and a stuck drill string
has forced a sidetrack.
The well will be completed with a 4-1/2”gas lift tie-back completion.
General sequence of operations pertaining to this drilling operation:
Rig
1. Set 9-5/8” whipstock at 4832’ 20ROHS.
2. PU 8-1/2” milling/drilling assembly and TIH.
3. Mill shoe track with 20’ of new hole. Perform FIT to 14.8 ppg EMW
4.Drill 150’ of rat hole.
5. Drill 8-1/2” production hole to 10139’MD, performing short trips as needed
x Pressure ramp below the Beluga H –10.1 ppg mud required to drill into the Beluga I
6. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
7. Perform Clean out run to polish bore
8. Perform liner lap test to 2000 psi.
9. Run 4-1/2”gas lift completion.
10. Land hanger. Test IA to 3000 psi and tubing to 3500 psi.
11. ND BOPE, NU tree and test void
Logging Plan
x Production Hole: Triple Combo (DEN/POR/RES)(DEN/POR/RES)
yp
a stuck drill stringp
has forced a sidetrack.
p pgp
Pressure ramp below the Beluga H –10.1 ppg mud required to drill into the Beluga I
Well will be sidetracked around lost BHA and continue to originally permitted bottom-hole
location. SFD 8/28/2023
Page 9 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
9. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 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 3700 psi in the Beluga U sand (7116' TVD). MASP is
2989 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 All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Page 10 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
8-1/2”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 10M Shaffer “U”Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 10M Shaffer “U”single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
10. 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 300-450 gpm. This can be achieved with one or both pumps.
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
4832’-TD 9.0-10.4 40-53 6-15 13-24 8.5-9.5 11.0
Page 12 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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
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 while drilling ahead.
11. Set Whipstock / Mill Window
1. Make up the 9-5/8” WIS Mechanical 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.
3. Orient whipstock as directed by the directional driller. The directional plan specifies 20 deg ROHS.
4. Set the top of the whipstock at ~4,832’ MD
5. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
Page 13 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
6. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 14.8 ppg.
¾**Assuming the kick zone is at TD, a FIT of 14.8 ppg EMW gives a 72 bbl KTV with 10.1 ppg mud weight.
¾Monitor OA during FIT and report and change in pressure.
7. POOH and LD milling assembly
¾Once out of the hole, inspect mill gauge and record.
¾Flow check well for 10 minutes to confirm no flow:
¾Before pulling off bottom.
¾Before pulling the BHA through the BOPE.
8. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
12. Drill 8-1/2” Hole Section
1. M/U 6-3/4” Directional only BHA w/ 8.5” bit
2. Drill 150’ of new hole to provide rathole for the LWD tools. POOH.
3. P/U 6-3/4” Sperry Sun motor drilling assy
x Triple combo (DEN, POR, RES)
4. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build and
drop sections of the wellbore.
5. Primary bit will be the Baker Hughes 8.5” Kymera. Ensure to have a backup PDC bit available on
location.
6. TIH to window. Shallow test MWD on trip in.
(DEN, POR, RES)
FIT to 14.8 ppg.
Page 14 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
7. Drill 8-1/2” hole to 10139’ MD using motor assembly.
x Ensure mud weight is at or above 10.1 ppg prior to drilling into the Beluga I
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 MW as necessary to maintain hole stability.
x Ensure mud engineer set up to perform HTHP fluid loss.
x Maintain API fluid loss < 6.
x Take MWD surveys every stand drilled.
x Minimize backreaming when working tight hole
8. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement
calculations. CBU, and pull a wiper trip back to the window.
9. TOH with drilling assembly, handle BHA as appropriate.
13. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure 4-1/2” CDS40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted and tally verified prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). 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
Ensure mud weight is at or above 10.1 ppg prior to drilling into the Beluga I
Keep swab and surge pressures low when tripping.
Page 15 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
x Centralizers will be run on 4-1/2” liner every joint to 6200’ 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 Tags 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 16 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Page 17 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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” window prior to going into open hole. Stage
pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting
pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15.P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
Page 18 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
14. Cement 4-1/2” Production Liner
1. Hold a pre-job safety meeting over the upcoming cmt operations.
2. Attempt to reciprocate the casing during cmt operations until hole gets sticky.
3. Pump 15 bbls 12.5 ppg spacer.
4. Test surface cmt lines to 4500 psi.
5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump 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 4632’ TMD (TOL).
7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs.
Slurry Information:
8. Drop DP dart and displace with 10.1 ppg WBM.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
9-5/8" Casing x 4-1/2" Liner (200') x 0.0535 bpf 10.7 60.1
8.5" OH x 4-1/2" Liner (9639-4832) x 0.0505 bpf x 1.4 340.0 1907.1
Total Lead 350.7 1967.2 837.1
8.5" OH x 4-1/2" Liner (500') x 0.0505 bpf x 1.4 = 35.4 198.4
4-1/2" Shoetrack 90' x 0.0152 bpf = 1.4 7.7
Total Tail 36.7 206.1 177.6
TOTAL CEMENT VOLUME 387 2173 178
Displacement DP+ Liner 148
Ta
i
l
L
e
a
d
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 19 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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.
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
Page 20 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 Wellez:
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
15. 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 2000 psi after cement has reached 500 psi compressive strength. 10 min operational
assurance test.
16. 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# H533
x SSSV to be placed at 450’
x GLM will be run. (depth TBD)
2. Swap the well over to FIW
x Circulate a hi-vis pill followed by a soap train per Baroid
Page 21 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 3500 psi. Charted 30 min test
5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
Page 22 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
17. BOP Schematic
Page 23 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
18. Wellhead Schematic
Page 24 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
19. 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.
Page 25 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
20. 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 26 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
21. Choke Manifold Schematic
Page 27 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Page 28 August 28, 2023
NCI A-18
Sidetrack Drilling Program
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22. Casing Design Information
Page 29 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
23. 8-1/2” Hole Section MASP
Page 30 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
24. Directional Program (wp07) - Attached separately.
! "
#$$
% #
% # !
!
2250
2625
3000
3375
3750
4125
4500
4875
5250
5625
6000
6375
6750
7125
7500
7875
Tr
u
e
V
e
r
t
i
c
a
l
D
e
p
t
h
(
7
5
0
u
s
f
t
/
i
n
)
2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500
Vertical Section at 194.00° (750 usft/in)
NCI A-18 wp04 tgt2
NCI A-18 wp07 tgt1
4000
4500
5000
5500
6000
6500
7 0 0 0
7 5 0 0
8 0 0 0
8 5 0 0
8 9 8 6
NCIU A-18 PB1
4000
4500
4870
NCIU A-18
9 5/8"_KOP
4 1/2"
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NCIU A-18 wp07
KOP: 12º/100' : 4832' MD, 3182.26'TVD : 20° RT TF
End Dir : 4849' MD, 3189.89' TVD
Start Dir 3º/100' : 4949' MD, 3233.3'TVD
End Dir : 5069.68' MD, 3286.9' TVD
Start Dir 3º/100' : 5289.68' MD, 3386.77'TVD
End Dir : 5374.87' MD, 3426.58' TVD
Start Dir 3º/100' : 6641.76' MD, 4035.29'TVD
End Dir : 8232.73' MD, 5262.63' TVD
Total Depth : 10138.83' MD, 7115.63' T
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Rig NCIU A-18
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586732.89 331999.46 61° 4' 36.4073 N 150° 56' 55.5330 W
SURVEY PROGRAM
Date: 2023-04-05T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
336.00 1254.00 Gyro-GC_Drill Pipe (NCIU A-18 PB1) 3_Gyro-GC_Drill pipe
1274.32 4832.00 MWD+AX+Sag (1) (NCIU A-18 PB1) 3_MWD+AX+Sag
4832.00 10138.83 NCIU A-18 wp07 (NCIU A-18) 3_MWD+AX+Sag
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Rig NCIU A-18 - Slot 1007, True North
Vertical (TVD) Reference:RKB @ 126.63usft
Measured Depth Reference:RKB @ 126.63usft
Calculation Method:Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:Rig NCIU A-18
Wellbore:NCIU A-18
Design:NCIU A-18 wp07
CASING DETAILS
TVD TVDSS MD Size Name
3182.26 3055.63 4832.00 9-5/8 9 5/8"_KOP
7115.63 6989.00 10138.83 4-1/2 4 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 4832.00 62.36 192.44 3182.26 -3020.84 -770.24 0.00 0.00 3117.45 KOP: 12º/100' : 4832' MD, 3182.26'TVD : 20° RT TF
2 4849.00 64.28 193.22 3189.89 -3035.65 -773.62 12.00 20.00 3132.63 End Dir : 4849' MD, 3189.89' TVD
3 4949.00 64.28 193.22 3233.30 -3123.35 -794.22 0.00 0.00 3222.72 Start Dir 3º/100' : 4949' MD, 3233.3'TVD
4 5069.68 63.00 197.00 3286.90 -3227.72 -822.38 3.00 111.48 3330.80 End Dir : 5069.68' MD, 3286.9' TVD
5 5289.68 63.00 197.00 3386.77 -3415.18 -879.69 0.00 0.00 3526.55 Start Dir 3º/100' : 5289.68' MD, 3386.77'TVD
6 5374.87 61.28 194.86 3426.58 -3487.59 -900.37 3.00 -132.68 3601.82 End Dir : 5374.87' MD, 3426.58' TVD
7 6641.76 61.28 194.86 4035.29 -4561.52 -1185.27 0.00 0.00 4712.77 Start Dir 3º/100' : 6641.76' MD, 4035.29'TVD
8 7351.24 40.00 195.00 4482.63 -5088.55 -1325.68 3.00 179.75 5258.11 NCI A-18 wp07 tgt1
9 8232.73 13.56 195.00 5262.63 -5468.76 -1427.56 3.00 180.00 5651.68 NCI A-18 wp04 tgt2 End Dir : 8232.73' MD, 5262.63' TVD
10 10138.83 13.56 195.00 7115.63 -5900.29 -1543.18 0.00 0.00 6098.36 Total Depth : 10138.83' MD, 7115.63' TVD
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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:Sean McLaughlin
To:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] NCIU A-18 (PTD 232-033) Sundry application
Date:Tuesday, August 29, 2023 2:16:40 PM
Bryan,
I’ve asked Sperry this same question about wellbore separation. At 30’ away magnetic
interference will be a problem and drilling parallel to PB1 with a low DLS assembly gives a lot
of reaction time. The plan is the minimum distance (85’ separation) that passes AC but in
practice would default to drilling further to the west while still honoring the original target.
The depth of the RA sources is well understood.
A 10ppg pore pressure is the maximum expected, not most likely. Drilling with a 10.1 ppg
mud seems to be a healthy mud weight based on A-12A and A-18 drilling. We monitor
connection gas very carefully and double backream every connection to verify. There has
been no evidence that a 10.1ppg mud is nearing actual pore pressure.
To avoid another swab kick both kick detection and prevention should be strengthened.
More focus and training will be placed on trips sheets while managing other problems. On
the prevention side drilling an 8.5” hole will significantly increase swab margin and kick
tolerance volume. Until I am more comfortable with kick detection and swab margins the rig
will be directed to pump out of hole to the Beluga H.
The 8.5” hole and lower ECDs will reduce loss circulation risk as well. In past Tyonek wells we
have had great success controlling loss circulation with cement.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, August 29, 2023 12:37 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A-18 (PTD 232-033) Sundry application
Sean,
I have a few questions about the sundry application for the sidetrack on NCIU A-18.
1. The distance from the Radioactive sources and the planned wellbore trajectory seems pretty
low. What precautions can you take to reduce the risk of accidental collision with the RA
sources?
2. Are you planning to drill the Beluga I with only 0.1 ppg overbalance? It doesn’t provide much
trip margin or allowance for swabbing, or for drop in fluid level due to losses. Seems like not
enough overbalance for a well that is likely to encounter swabbing and lost circulation.
3. What are you planning to do differently to avoid swabbing in another kick? If you do take a
kick, what will be done differently to minimize the kick volume?
4. If you encounter lost circulation, you should be prepared to run 7” drilling liner before drilling
into the overpressured Beluga I to prevent crossflow/underground blowout.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Abandon BHA w/ Sources
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?N/A
Yes No
9.Property Designation (Lease Number):10. Field:
North Cook Inlet Unit
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,986'N/A
Casing Collapse
Structural
Conductor
Surface 4750
Intermediate
Production
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: Yes Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
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
~4,736' (TOC Plug)~5,990' ~3,135' 2836 N/A
Tertiary System Gas Pool / Tertiary System Gas Pool
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
Bryan McLellan
8/26/2023
Tubing Grade: Tubing MD (ft):
N/A
Perforation Depth TVD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 17589 / ADL 37831
223-033
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20189-00-00
Hilcorp Alaska, LLC
NCIU A-18
Length Size
Proposed Pools:
N/A
TVD Burst
N/A
MD
6870
384'
3,465'
384'
5,430
30"
9-5/8"
384'
5,430'
Perforation Depth MD (ft):
N/A N/A
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
8/25/2023
N/A
N/A
Perforate
Repair Wepair Well
Exploratory Stratigraphic Development Service
BOP TestMechanical Integrity Test
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Drilling Manager
08/28/23
Monty M
Myers
By Grace Christianson at 2:53 pm, Aug 28, 2023
323-488
Abandon BHA w/ Sources
Verify plug location and integrity per 20AAC25.112(g)
All logs and records for lost hole section of hole must be labeled NCIU A-18PB1, API
Number 50-883-20189-70-00. Permit to Drill Number remains unchanged.
BJM 8/30/23 DSR-8/28/23
Submit a copy of the report sent to the NRC for Notification of incidents and lost sources; abandonment procedures for irretrievable sources,
to be included in the 10-407.
Affix to the wellhead a permanent surface marker as a visual warning to any person who may reenter the hole, showing that it contains
a radioactive source. The marker to contain PTD number and info required in NRC regulation 39.15(a)(5)(iii) within 30 days of moving the rig off the well.
SFD 8/28/2023
10-407
($8JLC 8/30/2023
08/31/23
RBDMS JSB 090523
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.31 16:03:56
-08'00'
Well Prognosis
Well: NCIU A-18
Date: 8/24/23
Well Name:NCIU A-18 API Number:50-883-20189-00
Current Status:Abandon sources /
Sidetrack
Estimated Start Date:8/27/2023 Rig:Rig 151
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:TBD
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:223-033
First Call Engineer:Sean McLaughlin (907)-223-6784 (M)
Second Call Engineer
AFE Number:
Brief Well Summary –
The A-18 production hole was drilled to a TD of 8986’. The well was shut in during a trip due to a swab kick.
After the well was dead the drill string could not be moved. Eline ran a string shot to back off the DP at
5377’. This left a 1937’ fish in hole that included drill pipe, HWDP, and a drilling BHA with RA sources. Fishing
jars were run and 12hrs of jarring yielded no movement. Circulation was not possible through the BHA either.
Wireline ran inside the drillpipe and made a RCT cut at 6000’. Wireline tools were not able to go deeper than
6000’ due to debris. No fish movement or circulation was gained. A tubing punch was shot at 5950’ and
circulation was not possible. Debris inside the drillpipe and the inability to cut pipe had made recovery
impossible. The plan forward is to abandon the BHA with cement and then sidetrack to the original target.
Well Information:
x Top of Tertiary System Gas Pool at 5045’
x Top of fish at 5377’ MD (4-1/2” CDS40 DP Box up)
x 9-5/8” Casing Shoe at 5430’
x Potential top of sticking depth (eline free point) 5610’
x Depth of upper RA source at 7225’
x Bit depth at 7314’ (in Sterling sand)
x Openhole depth at 8986’ (in Beluga J)
Sidetrack Plan:
1. HES to Notify NRC of stuck source and abandonment.
2. Run 9-5/8” cement retainer to 5009’
3. Squeeze 40 bbls of 12# cement below the retainer
4. Lay in 20 bbls of 15.8# cement plug on top of retainer
a. TOF 5377’
b. Upper source – 7236’ (the DP, HWDP, and flex joints will be considered a mechanical deflection
device)
c. Include red dye in cement
5. WOC. PU 8.5” milling assembly. Clean out cement to 4860’
6. Run 9-5/8” whipstock and set at 4832’
7. Submit change of approved program Sundry for sidetrack
8. HES to file abandonment completion with the NRC within 30 days
Attachments
1.Proposed Abandonment Schematic
2.BHA Tally
e well was shut in during a trip due to a swab kick.
Verify cement plug location and integrity per 20AAC25.112(g)
-bjm
o abandon the BHA with cement and then sidetrack to the original target.
Updated by CJD 08-28-2023
Current SCHEMATIC
North Cook Inlet Unit
NCIU A-18
PTD: 223-033
API: 50-883-20189-00-00
TD = 8,986’ MD / TVD = 5,990’
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 TXP 8.681”Surf 5,430’
8-1/2”Drilling BHA / pipe ----5,377’7,314’
30”
9-5/8”
12-1/4”
hole
Fish BHA
w/ sources
JEWELRY DETAIL
No.Depth ID OD Item
1 1,006’--ES Cementer
2 5,009’--Cement Retainer
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 - 955 sx / Stg 2 1070 sx
6-3/4”
OH
5,377’Top of Fish
7,314’Bottom of Fish (Bit)
60 bbls red dye cement to abandon Fish 40 bbls below, 20 bbls on top of retainter
(TOC ±4,736’ MD)
6-3/4”
hole
1
WELL INFORMATION Created On : Aug 16 2023
Customer :Hilcorp Alaska, LLC
Well Name :NCIU A-18
Job Number :AK-XX-0908720847
Platform :Tyonek
Field Name :North Cook Inlet
Country :USA
BHA Tally
Drillstring
IADC Rig BHA#
Run#600
Length
(ft)Length
Cumulative
COMPONENT DATA
(ft)
Item
#Description Serial Number OD ID Gauge Weight Top
Connection
Bottom
Connection(in)(in)(in)(lbpf)
1 6 3/4" NOV TKC63
6X10 Jets A290293 5.000 2.750 6.750 46.67 P 3-1/2" REG 1.00 1.00
2 4 3/4" Terraforce 5/6
Lobe 8.3 Stg 10475834 4.720 2.750 39.39 B 3-1/2" IF B 3-1/2" REG 29.66 30.66
3 4 3/4" DM Collar 12113036 4.750 2.610 48.20 B 3-1/2" IF P 3-1/2" IF 9.18 39.84
4 4 3/4" SP4 Collar 90729366R24 4.750 1.250 48.20 B 3-1/2" IF P 3-1/2" IF 23.91 63.75
5 4 3/4" ALD Collar 90732937NIL2
4 4.750 1.250 5.540 45.50 B 3-1/2" IF P 3-1/2" IF 14.33 78.08
Stabilizer 5.540
6 4 3/4" CTN Collar 90732937NIL2
4 4.750 1.250 50.50 B 3-1/2" IF P 3-1/2" IF 11.14 89.22
7 4 3/4" PWD 90729540W4 4.750 1.250 47.90 B 3-1/2" IF P 3-1/2" IF 9.18 98.40
8 4 3/4" TM Collar 1293597 4.750 2.610 48.20 B 3-1/2" IF P 3-1/2" IF 11.09 109.49
9 4 3/4" IBS 10452704 4.790 2.000 6.500 50.71 B 3-1/2" IF P 3-1/2" IF 4.23 113.72
10 4 3/4" Flex NMDC 13271760 4.970 2.250 52.56 B 3-1/2" IF P 3-1/2" IF 31.09 144.81
11 4 3/4" Flex NMDC 13271757 5.000 2.250 53.37 B 3-1/2" IF P 3-1/2" IF 31.08 175.89
12 X-Over Sub 3 1/2 IF Pin
x CDS-40 Box 4672 5.400 2.250 64.50 B 5" CDS40 P 3-1/2" IF 2.69 178.58
13 6 jnts. 4 1/2" CDS-40
HWDP 4.500 2.750 40.65 P 5" CDS40 185.15 363.73
14 X-Over Sub CDS40 Pin
x XT-39 Box 5264 5.220 2.250 59.38 B 4" XT39 P 5" CDS40 1.25 364.98
15 4 3/4" Yellow Jacket Hyd
Jar A30492HE 4.750 2.500 43.66 B 4" XT39 P 4" XT39 30.58 395.56
16 X-Over Sub XT-39 Pin x
CDS-40 Box 5266 5.270 2.500 57.61 B 5" CDS40 P 4" XT39 1.37 396.93
17 11 jnts. 4 1/2" CDS-40
HWDP 4.500 2.250 40.65 P 5" CDS40 338.90 735.83
Total:735.83
BIT DATA
Bit Number :6 Nozzles :6x10
Bit Size (in) :6.750 TFA (in2) :0.4602
Manufacturer :NOV / ReedHycalog Dull Grade In :
Model :TKC63 Dull Grade Out :
Serial Number :A290293
INSITE V9.2.0 Page 1Job No: AK-XX-0908720847 Well Name: NCIU A-18 BHA Tally
RA
S
o
u
r
c
e
Entire drilling assembly and 1201' of 4-1/2" DP LIH
MOTOR DATA
Motor Number : Bend (deg) :1.506
OD (in) :4.720 Nozzles (32nd) :0.0
Manufacturer :Sperry Drilling Avg Diff Press :
Model :Terraforce Cumul Cir Hrs :
Serial Number :10475834
BHA Weight (klb) (klb)
in Air (Total) :31.47 in Mud (Total) :27.15 Mud Weight (ppg) :9.00
in Air (Below Jars) :16.28 in Mud (Below Jars) :14.05
COMMENTS
BHA #5 Run 500
Motor assembly for 6 3/4" Production
4 3/4” Terra-force 5/6 8.3 stg ABH @ 1.50° 1.0 Rev/Gal
Dir= 34.88' Res= 49.07' DGR= 56.13' ALD= 68.28' CTN= 83.02' PWD= 94.73'
RFO= 397/477 X 360= 299.62
Planned Parameters:200-250 GPM,50-80 RPM, 5k-15kWOB
Torque bit to 8K, 3 1/2 IF=10K
Jar Hrs In =46.09 Jar Hrs Out =
Bit Dull Grading:
INSITE V9.2.0 Page 2Job No: AK-XX-0908720847 Well Name: NCIU A-18 BHA Tally
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Cc:Davies, Stephen F (OGC)
Subject:Re: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Date:Saturday, August 26, 2023 9:40:09 PM
Attachments:image001.png
Sean,
I agree with your assessment. Fluid movement past the stuck BHA is unlikely. Hilcorp has
approval to plug back with cement per the plan you sent in this email chain.
Regards
Bryan
Sent from my iPhone
On Aug 26, 2023, at 9:18 PM, Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com> wrote:
Bryan,
Given poor hole conditions prior to getting stuck, coals, LCM, and barite sag there is
most likely no longer a conduit for gas. There is water in the Beluga as well so a column
of gas is not a given. There are also low pressure sands below the base cement that
would preferentially take flow. A few of those Sterling sands are 200 psi sands and a
large tank. An upward Frac from base cement is not probable.
The well has not taken any fluid for the last few days. I believe we are packed off with
LCM and Barite near the casing shoe. The eline stuck point is 5640’. We have not
recovered any drillpipe after the initial back off. I don’t believe wan can recover
anything measurable at this point.
It is likely to get cement below the retainer we will need to breakdown the casing
shoe. That is one of the reasons the retainer depth is requested above the shoe, so we
can get some vertical cement volume.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Saturday, August 26, 2023 8:39 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Sean,
It’s not a good situation since 10 ppg gas column from TD will frac out below the base
of your planned cement and potentially frac upward. See diagram below showing pore
pressure at TD minus gas gradient. Is there any chance to fish more drill pipe from the
hole so you can place cement plug deeper, below 3800’ TVD?
<image001.png>
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Saturday, August 26, 2023 8:21 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Bryan,
The top hydrocarbon bearing zone is the Sterling at 5555’ MD. The Beluga is the main
target and there are many stacked hydrocarbon zones in the entire production hole
section. The Beluga I (8455’ MD) and below is assumed to be overpressured at 10ppg.
I’ve attached a current log and direction survey.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Saturday, August 26, 2023 7:54 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Sean,
Can you send the directional survey and depth of any hydrocarbon-bearing or
overpressured zones?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Saturday, August 26, 2023 5:53 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Cody Dinger <cdinger@hilcorp.com>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Bryan,
A wireline cut and tubing punch were both unsuccessful due to suspected debris in the
drill string. We are pivoting to abandonment operations ahead of a sidetrack. I’ve
attached the plan, schematic, and BHA sheet. Hilcorp requests verbal approval to
move forward with he abandonment with the Sundry request to follow on Monday. An
MOC for the sidetrack will be sent tomorrow.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, August 25, 2023 12:27 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Thanks for the update.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Friday, August 25, 2023 11:57 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
No measurable progress yesterday. Eline free point indicated the stuck point is ~200’
below the casing shoe. We ran a string shot and backed off drill pipe just inside the
casing shoe and jarred for 12 hrs. Eline rigged back up for a cut but couldn’t get the
RCT centralizers past the accelerator. We don’t want to shoot the accelerator
centralized.
Looking ahead we will back off the fishing tools, run slick drill pipe, run an eline cutter,
pull drill pipe, run fishing tools and attempt to pull the cut section. That should take us
until Saturday evening. If still no progress we may move towards abandonment.
I’m working on a draft abandonment program now assuming no recovery of the fish
(most probable case).
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, August 25, 2023 11:31 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Did you recover the RA fish?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
From: McLellan, Bryan J (OGC)
Sent: Thursday, August 24, 2023 1:50 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Sean,
I recommend submitting a sundry tomorrow morning if it still looks like you will need to
sidetrack.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 24, 2023 9:31 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
The plan is to sidetrack.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 24, 2023 9:28 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] RE: A-18 (223-033) Stuck BHA with sources
Would you plan to sidetrack around the BHA, or P&A the entire well?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image002.jpg>
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
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.
Sent: Thursday, August 24, 2023 8:45 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: A-18 (223-033) Stuck BHA with sources
Bryan,
On well Tyonek well (A-18) we have a stuck BHA that has RA sources. We have been
fishing 8 hours with no movement. The intention is to try a couple more runs but the
outlook for recovery is not good. We may move towards abandonment over the
weekend. How would you like to prepare for that? Do you want a draft Sundry now?
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
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
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The information contained in this email message is confidential and may be legally privileged and is intended only for
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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
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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.
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
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If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone
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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.
The information contained in this email message is confidential and may be legally privileged and is intended only for
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1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other:
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?N/A
Yes No
9. Property Designation (Lease Number):10. Field:
North Cook Inlet Unit
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,986'N/A
Casing Collapse
Structural
Conductor
Surface 4750
Intermediate
Production
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:
Contact Email:
Contact Phone:
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
~4,736' (TOC Plug)~5,990'~3,135'2989 N/A
Tertiary System Gas Pool / Tertiary System Gas Pool
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):
N/A
Perforation Depth TVD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 17589 / ADL 37831
223-033
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20189-00-00
Hilcorp Alaska, LLC
NCIU A-18
Length Size
Proposed Pools:
N/A
TVD Burst
N/A
MD
6870
384'
3,465'
384'
5,430
30"
9-5/8"
384'
5,430'
Perforation Depth MD (ft):
N/A N/A
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
8/28/2023
N/A
N/A
m
n
P
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Drilling Manager
08/28/23
Monty M
Myers
By Grace Christianson at 3:11 pm, Aug 28, 2023
323-489
X
DSR-8/28/23
Lost circulation zones must be cured or isolated prior to penetrating the overpressured Beluga I interval.
SFD 8/28/2023
8/28/2023
BOP test to 3500 psi. Annular test to 2500 psi.
10-407
Change Approved Programm
BJM 8/30/23*&:
08/30/23
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.30 10:19:53
-08'00'
RBDMS JSB 083123
A-18 Drilling Program
Tyonek
Sean McLaughlin
Sidetrack Drilling Program
August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Contents
1. Well Summary...............................................................................................................................2
2. Management of Change Information............................................................................................3
3. Tubular Program...........................................................................................................................4
4. Drill Pipe Information...................................................................................................................4
5. Internal Reporting Requirements.................................................................................................5
6. Current Wellbore Schematic.........................................................................................................6
7. Planned Wellbore Schematic.........................................................................................................7
8. Drilling Summary..........................................................................................................................8
9. Mandatory Regulatory Compliance / Notifications......................................................................9
10. Preparatory Work and Mud Program........................................................................................11
11. Set Whipstock / Mill Window......................................................................................................12
12. Drill 8-1/2” Hole Section ..............................................................................................................13
13. Run 4-1/2” Production Liner.......................................................................................................14
14. Cement 4-1/2” Production Liner .................................................................................................18
15. Wellbore Clean Up & Displacement...........................................................................................20
16. Run Completion Assembly..........................................................................................................20
17. BOP Schematic............................................................................................................................22
18. Wellhead Schematic.....................................................................................................................23
19. Anticipated Drilling Hazards......................................................................................................24
20. FIT Procedure..............................................................................................................................25
21. Choke Manifold Schematic .........................................................................................................26
22. Casing Design Information..........................................................................................................28
23. 8-1/2” Hole Section MASP...........................................................................................................29
24. Directional Program (wp07) - Attached separately...................................................................30
Page 2 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
1. Well Summary
Well NCI A-18
Drilling Rig Rig 151
Leg & Slot Leg 1 / Slot 7
Directional plan wp05
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 10146’MD / 7116’TVD
AFE Number
AFE Days
AFE Drilling Amount
Work String 4.5” 16.6# S-135 CDS40
RKB –AMSL 126.6’
MSL to ML 73.3’
Well_Desc X_SPAK4_27 Y_SPAK4_27 X_SPAK4_83 Y_SPAK4_83 Location
NCI A-18_SHL 331999.46 2586732.89 1472024.77 2586494.58 1247' FNL, 980' FWL, Sec 6, T11N, R9W, SM, AK
NCI A-18_TPH 331099.18 2583356.73 1471124.33 2583118.53 644' FSL, 129' FWL, Sec 6, T11N, R9W, SM, AK
NCI A-18_BHL 330474.09 2580847.92 1470499.13 2580609.82 1874' FNL, 459' FEL, Sec 12, T11N, R10W, SM, AK
Page 3 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
2. Management of Change Information
Date: August 28, 2023
Subject: Changes to Approved Permit to Drill
File #: NCI A-18 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.
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
3. Tubular Program
Hole Section OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)Grade Conn Burst
(psi)
Collap
se
(psi)
Tension
(k-lbs)
Conductor
(previously
installed)
30”Assume
29”--Assume
158#X-56 Weld 1630 230
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 TXP 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)
Prod 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 16,176 10,959 468k
Page 5 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 Try to 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. Dennis LaRoche: C: (907) 513-7090
x Spills:
i. Keegan Fleming: C:907-350-9439
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 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
6. Current Wellbore Schematic
Page 7 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
7. Planned Wellbore Schematic
Page 8 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
8. Drilling Summary
A-18 is a 10,139’ MD / 7116’ TVD development gas well drilled from leg 1 slot #7 off the Tyonek platform.
The base plan is an infill wellbore to the Beluga U. The surface hole has been drilled and a stuck drill string
has forced a sidetrack.
The well will be completed with a 4-1/2”gas lift tie-back completion.
General sequence of operations pertaining to this drilling operation:
Rig
1. Set 9-5/8” whipstock at 4832’ 20ROHS.
2. PU 8-1/2” milling/drilling assembly and TIH.
3. Mill shoe track with 20’ of new hole. Perform FIT to 14.8 ppg EMW
4.Drill 150’ of rat hole.
5. Drill 8-1/2” production hole to 10139’MD, performing short trips as needed
x Pressure ramp below the Beluga H –10.1 ppg mud required to drill into the Beluga I
6. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
7. Perform Clean out run to polish bore
8. Perform liner lap test to 2000 psi.
9. Run 4-1/2”gas lift completion.
10. Land hanger. Test IA to 3000 psi and tubing to 3500 psi.
11. ND BOPE, NU tree and test void
Logging Plan
x Production Hole: Triple Combo (DEN/POR/RES)(DEN/POR/RES)
yp
a stuck drill stringp
has forced a sidetrack.
p pgp
Pressure ramp below the Beluga H –10.1 ppg mud required to drill into the Beluga I
Well will be sidetracked around lost BHA and continue to originally permitted bottom-hole
location. SFD 8/28/2023
Page 9 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
9. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 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 3700 psi in the Beluga U sand (7116' TVD). MASP is
2989 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 All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
Page 10 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
8-1/2”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 10M Shaffer “U”Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 10M Shaffer “U”single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
10. 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 300-450 gpm. This can be achieved with one or both pumps.
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
4832’-TD 9.0-10.4 40-53 6-15 13-24 8.5-9.5 11.0
Page 12 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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
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 while drilling ahead.
11. Set Whipstock / Mill Window
1. Make up the 9-5/8” WIS Mechanical 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.
3. Orient whipstock as directed by the directional driller. The directional plan specifies 20 deg ROHS.
4. Set the top of the whipstock at ~4,832’ MD
5. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
Page 13 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
6. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 14.8 ppg.
¾**Assuming the kick zone is at TD, a FIT of 14.8 ppg EMW gives a 72 bbl KTV with 10.1 ppg mud weight.
¾Monitor OA during FIT and report and change in pressure.
7. POOH and LD milling assembly
¾Once out of the hole, inspect mill gauge and record.
¾Flow check well for 10 minutes to confirm no flow:
¾Before pulling off bottom.
¾Before pulling the BHA through the BOPE.
8. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
12. Drill 8-1/2” Hole Section
1. M/U 6-3/4” Directional only BHA w/ 8.5” bit
2. Drill 150’ of new hole to provide rathole for the LWD tools. POOH.
3. P/U 6-3/4” Sperry Sun motor drilling assy
x Triple combo (DEN, POR, RES)
4. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build and
drop sections of the wellbore.
5. Primary bit will be the Baker Hughes 8.5” Kymera. Ensure to have a backup PDC bit available on
location.
6. TIH to window. Shallow test MWD on trip in.
(DEN, POR, RES)
FIT to 14.8 ppg.
Page 14 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
7. Drill 8-1/2” hole to 10139’ MD using motor assembly.
x Ensure mud weight is at or above 10.1 ppg prior to drilling into the Beluga I
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 MW as necessary to maintain hole stability.
x Ensure mud engineer set up to perform HTHP fluid loss.
x Maintain API fluid loss < 6.
x Take MWD surveys every stand drilled.
x Minimize backreaming when working tight hole
8. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement
calculations. CBU, and pull a wiper trip back to the window.
9. TOH with drilling assembly, handle BHA as appropriate.
13. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure 4-1/2” CDS40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted and tally verified prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). 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
Ensure mud weight is at or above 10.1 ppg prior to drilling into the Beluga I
Keep swab and surge pressures low when tripping.
Page 15 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
x Centralizers will be run on 4-1/2” liner every joint to 6200’ 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 Tags 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 16 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Page 17 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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” window prior to going into open hole. Stage
pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting
pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15.P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
Page 18 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
14. Cement 4-1/2” Production Liner
1. Hold a pre-job safety meeting over the upcoming cmt operations.
2. Attempt to reciprocate the casing during cmt operations until hole gets sticky.
3. Pump 15 bbls 12.5 ppg spacer.
4. Test surface cmt lines to 4500 psi.
5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump 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 4632’ TMD (TOL).
7. Displacement fluid will be CLEAN drilling mud. Please independently verify with actual inputs.
Slurry Information:
8. Drop DP dart and displace with 10.1 ppg WBM.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
9-5/8" Casing x 4-1/2" Liner (200') x 0.0535 bpf 10.7 60.1
8.5" OH x 4-1/2" Liner (9639-4832) x 0.0505 bpf x 1.4 340.0 1907.1
Total Lead 350.7 1967.2 837.1
8.5" OH x 4-1/2" Liner (500') x 0.0505 bpf x 1.4 = 35.4 198.4
4-1/2" Shoetrack 90' x 0.0152 bpf = 1.4 7.7
Total Tail 36.7 206.1 177.6
TOTAL CEMENT VOLUME 387 2173 178
Displacement DP+ Liner 148
Ta
i
l
L
e
a
d
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 19 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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.
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
Page 20 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 Wellez:
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
15. 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 2000 psi after cement has reached 500 psi compressive strength. 10 min operational
assurance test.
16. 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# H533
x SSSV to be placed at 450’
x GLM will be run. (depth TBD)
2. Swap the well over to FIW
x Circulate a hi-vis pill followed by a soap train per Baroid
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NCI A-18
Sidetrack Drilling Program
PTD# 223-033
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 3500 psi. Charted 30 min test
5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
Page 22 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
17. BOP Schematic
Page 23 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
18. Wellhead Schematic
Page 24 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
19. 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.
Page 25 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
20. 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 26 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
21. Choke Manifold Schematic
Page 27 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
Page 28 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
22. Casing Design Information
Page 29 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
23. 8-1/2” Hole Section MASP
Page 30 August 28, 2023
NCI A-18
Sidetrack Drilling Program
PTD# 223-033
24. Directional Program (wp07) - Attached separately.
! "
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2625
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2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500
Vertical Section at 194.00° (750 usft/in)
NCI A-18 wp04 tgt2
NCI A-18 wp07 tgt1
4000
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5000
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NCIU A-18 wp07
KOP: 12º/100' : 4832' MD, 3182.26'TVD : 20° RT TF
End Dir : 4849' MD, 3189.89' TVD
Start Dir 3º/100' : 4949' MD, 3233.3'TVD
End Dir : 5069.68' MD, 3286.9' TVD
Start Dir 3º/100' : 5289.68' MD, 3386.77'TVD
End Dir : 5374.87' MD, 3426.58' TVD
Start Dir 3º/100' : 6641.76' MD, 4035.29'TVD
End Dir : 8232.73' MD, 5262.63' TVD
Total Depth : 10138.83' MD, 7115.63' T
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Rig NCIU A-18
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586732.89 331999.46 61° 4' 36.4073 N 150° 56' 55.5330 W
SURVEY PROGRAM
Date: 2023-04-05T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
336.00 1254.00 Gyro-GC_Drill Pipe (NCIU A-18 PB1) 3_Gyro-GC_Drill pipe
1274.32 4832.00 MWD+AX+Sag (1) (NCIU A-18 PB1) 3_MWD+AX+Sag
4832.00 10138.83 NCIU A-18 wp07 (NCIU A-18) 3_MWD+AX+Sag
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Rig NCIU A-18 - Slot 1007, True North
Vertical (TVD) Reference:RKB @ 126.63usft
Measured Depth Reference:RKB @ 126.63usft
Calculation Method:Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:Rig NCIU A-18
Wellbore:NCIU A-18
Design:NCIU A-18 wp07
CASING DETAILS
TVD TVDSS MD Size Name
3182.26 3055.63 4832.00 9-5/8 9 5/8"_KOP
7115.63 6989.00 10138.83 4-1/2 4 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 4832.00 62.36 192.44 3182.26 -3020.84 -770.24 0.00 0.00 3117.45 KOP: 12º/100' : 4832' MD, 3182.26'TVD : 20° RT TF
2 4849.00 64.28 193.22 3189.89 -3035.65 -773.62 12.00 20.00 3132.63 End Dir : 4849' MD, 3189.89' TVD
3 4949.00 64.28 193.22 3233.30 -3123.35 -794.22 0.00 0.00 3222.72 Start Dir 3º/100' : 4949' MD, 3233.3'TVD
4 5069.68 63.00 197.00 3286.90 -3227.72 -822.38 3.00 111.48 3330.80 End Dir : 5069.68' MD, 3286.9' TVD
5 5289.68 63.00 197.00 3386.77 -3415.18 -879.69 0.00 0.00 3526.55 Start Dir 3º/100' : 5289.68' MD, 3386.77'TVD
6 5374.87 61.28 194.86 3426.58 -3487.59 -900.37 3.00 -132.68 3601.82 End Dir : 5374.87' MD, 3426.58' TVD
7 6641.76 61.28 194.86 4035.29 -4561.52 -1185.27 0.00 0.00 4712.77 Start Dir 3º/100' : 6641.76' MD, 4035.29'TVD
8 7351.24 40.00 195.00 4482.63 -5088.55 -1325.68 3.00 179.75 5258.11 NCI A-18 wp07 tgt1
9 8232.73 13.56 195.00 5262.63 -5468.76 -1427.56 3.00 180.00 5651.68 NCI A-18 wp04 tgt2 End Dir : 8232.73' MD, 5262.63' TVD
10 10138.83 13.56 195.00 7115.63 -5900.29 -1543.18 0.00 0.00 6098.36 Total Depth : 10138.83' MD, 7115.63' TVD
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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:Sean McLaughlin
To:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] NCIU A-18 (PTD 232-033) Sundry application
Date:Tuesday, August 29, 2023 2:16:40 PM
Bryan,
I’ve asked Sperry this same question about wellbore separation. At 30’ away magnetic
interference will be a problem and drilling parallel to PB1 with a low DLS assembly gives a lot
of reaction time. The plan is the minimum distance (85’ separation) that passes AC but in
practice would default to drilling further to the west while still honoring the original target.
The depth of the RA sources is well understood.
A 10ppg pore pressure is the maximum expected, not most likely. Drilling with a 10.1 ppg
mud seems to be a healthy mud weight based on A-12A and A-18 drilling. We monitor
connection gas very carefully and double backream every connection to verify. There has
been no evidence that a 10.1ppg mud is nearing actual pore pressure.
To avoid another swab kick both kick detection and prevention should be strengthened.
More focus and training will be placed on trips sheets while managing other problems. On
the prevention side drilling an 8.5” hole will significantly increase swab margin and kick
tolerance volume. Until I am more comfortable with kick detection and swab margins the rig
will be directed to pump out of hole to the Beluga H.
The 8.5” hole and lower ECDs will reduce loss circulation risk as well. In past Tyonek wells we
have had great success controlling loss circulation with cement.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, August 29, 2023 12:37 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A-18 (PTD 232-033) Sundry application
Sean,
I have a few questions about the sundry application for the sidetrack on NCIU A-18.
1. The distance from the Radioactive sources and the planned wellbore trajectory seems pretty
low. What precautions can you take to reduce the risk of accidental collision with the RA
sources?
2. Are you planning to drill the Beluga I with only 0.1 ppg overbalance? It doesn’t provide much
trip margin or allowance for swabbing, or for drop in fluid level due to losses. Seems like not
enough overbalance for a well that is likely to encounter swabbing and lost circulation.
3. What are you planning to do differently to avoid swabbing in another kick? If you do take a
kick, what will be done differently to minimize the kick volume?
4. If you encounter lost circulation, you should be prepared to run 7” drilling liner before drilling
into the overpressured Beluga I to prevent crossflow/underground blowout.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+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
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1
Regg, James B (OGC)
From:Shane Hauck <shauck@hilcorp.com>
Sent:Monday, August 21, 2023 2:25 PM
To:Regg, James B (OGC)
Cc:Dennis Laroche - (C); rig151oim (enterpriseoffshore); Sean McLaughlin; Monty Myers; Steve
Dambacher - (C); Sloan Sunderland; Christopher Yearout - (C)
Subject:RE: Hilcorp bope usage report rig #151
Mr. Regg
Just an update. We have the well killed and open since 14:31 hrs yesterday and with 6‐7 BPH loss rate. Unfortunately
our pipe is stuck and been working same since with no jar acƟon. Our plan is to free point and back off and pooh for
bope test then fishing tools. Would you like me to esƟmate a test Ɵme and give formal noƟce via web site?
Thanks
Shane R Hauck
Hilcorp DSM
Rig 907‐776‐7945
From: Shane Hauck
Sent: Saturday, August 19, 2023 3:37 PM
To: Regg, James B (CED) <jim.regg@alaska.gov>
Cc: Dennis Laroche ‐ (C) <Dennis.Laroche@hilcorp.com>; rig151oim (enterpriseoffshore)
<rig151oim@enterpriseoffshore.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Monty Myers
<mmyers@hilcorp.com>; Steve Dambacher ‐ (C) <Steve.Dambacher@hilcorp.com>; Sloan Sunderland
<ssunderland@hilcorp.com>; Christopher Yearout ‐ (C) <Christopher.Yearout@hilcorp.com>
Subject: Hilcorp bope usage report rig #151
Mr. Regg
please see our bope usage report
Thanks
Shane R Hauck
Hilcorp DSM
Rig 907‐7767945
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North Cook Inlet Unit A-18PTD 2230330
AOGCC BOPE USAGE REPORT FORM (Well Control event)
Drilling Manager Name: Monty M Myers Drill Site Forman: Shane Hauck
Contact Number: 907‐777‐8431 Contact Number: 907‐776‐7945
HILCORP Velocity Number:
Rig Name & Well Pad or Drill Site & Well Name: NCIU A‐18 Tyonek platform rig Spartan #151
Permit To Drill (PTD) Number: 2230330
Date and Time of Incident: 8‐18‐23 @ 1704 hrs
Original Scope of Work: Drilling 6‐3/4” production hole as per well program
Operational Description Leading up to Well Control Event: A‐18 was drilled with 6‐3/4” hole to 8986’ MD. After
bottoms up circulation and static flow check the BHA started pumping out of hole for a BHA change. The assembly
was pulling tight with 70k overpulls and requiring pipe rotation to break free. At 8579’ a stand was pulled dry w/ only
20‐30k overpulls. A 60 bbl LCM pill was pumped and spotted out of bit. The rig resumed pulling out of hole on
elevators to 7001’ when the trip sheet was determined to be 12 bbls off. The well was flow checked with a positive
result. The BHA was RIH to 7314’ and shut in with the annular preventer. The SICP was 717psi and the influx volume
was 49 bbls. The well is being killed with the first step of the drillers method. A loss zone is present and is suspected
to be at 7635’ MD. The kick is due to swabbing, no MW increase is planned at this time.
BOPE Used and Reason: Annular preventor closed and choke HCR valve open. Circulated first step of drillers method
using choke manifold.
Current BOPE test time/date
17:30 08/09/2023
Is a BOPE re‐test required after use: Yes
BOPE Retest time/date and result : Will be completed once out of hole after well control event
Plan Forward: Circulate out influx, heal losses, bottom kill well. Pull out of hole for bope test
Additional Comments:
ACTIONS REQUIRED: by Drilling Foreman
1.Timely email notification of BOPE re‐test time estimate to AOGCC North Slope Inspectors is required
following any WC incident to allow the State to witness re‐test as required.
2.Email the completed BOPE Usage Report form to AOGCC North Slope Inspectors within 24 hours of a
WC incident: doa.aogcc.prudhoe.bay@alaska.gov
3.Complete AOGCC BOPE Test report form 10‐424 and send to three AOGCC addresses (noted in form)
within 5 days following the test/retest. This is applicable to Well Control events Only.
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 Dr., Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet Unit, Tertiary System Gas Pool, NCIU A-18
Hilcorp Alaska, LLC
Permit to Drill Number: 223-033
Surface Location: 1247’ FNL, 980’ FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 1874’ FNL, 459’ FEL, Sec 12, T11N, R10W, 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 AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of June, 2023.
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.06.29 16:14:30
-05'00'
223-033
Shut-in close approach well A-13 while drilling from conductor to 500' MD.
BJM 6/28/23 SFD 6/29/2023 DSR-4/13/23
50-883-20189-00-00
BOP test to 3500 psi. Annular test to 2500 psi.
MITIA to 3000 psi after running tubing.
Submit FIT/LOT data within 48 hrs of obtaining data.
JLC 6/29/23 GCW 06/29/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.06.29 16:14:52 -05'00'
Shut-in A-13 while drilling from
conductor to 500' MD. bjm
Verified cement calcs. -bjm
Verified Cement calcs
3000 psi per Sean McLaughlin email attached.
Superseded by table in
appended email dated
6/13/2023. SFD 6/13/2023
?
?
?
SFD
?
1
Davies, Stephen F (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Thursday, June 15, 2023 8:34 AM
To:Davies, Stephen F (OGC)
Cc:Matthew Petrowsky
Subject:RE: [EXTERNAL] RE: NCIU_A-18 (PTD #223-033) - Questions
HiSteve,
IspoketotheGeologist(cc’daswell)anditisbesttokeepthedepthsthatarecurrentlyintheprogram.Ashoedepth
of3420’TVDisintherangeofuncertaintyandisontheshallowside.Drillingthroughthedisposalzoneisniceforshoe
strengthbutwedon’twanttodrillintotheSterling.Thedisposalzonewillbeisolatedwithcementeitherway,surface
casingcementispreferable.Thedisposalzonehasbeendrilledthrough8timesinthelasttwoyearsandweare
comfortablemakingthecorrectpick.Anotherreasonnottotweakthecasingshoedepthontheprogramisthatit
wouldaffectcementvolumes,KTVcalculations,andschematics.Aswithanycasingpickallwillbeadjustedoncethe
casingMD/TVDisknown.
Regards,
Sean
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Wednesday,June14,20232:35PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
No,justalistingofanyrevisedvaluesbyemailwouldbefine.
Thanks,
SteveDavies
AOGCC
From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Sent:Wednesday,June14,20232:32PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
WoulditbebestjusttoresubmitthePTDdocument?
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Wednesday,June14,20232:25PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
2
Sean,
Ifyouwouldn’tmindupdatingthenumbersinanemail.Itwilleliminatetheapparentdiscrepanciesandinevitable
questionsthatwillarisefromothers.
Thanksforyourhelp,
SteveDavies
AOGCC
From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Sent:Wednesday,June14,20232:18PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
Steve,
BasedonyourpreviousquestiontheGeoupdatedprobablepicksbasedonAͲ14,15,16.Thatiswhythedepth
discrepancy.Icangobacktotheoriginalpicksifithelpsthatprogramnumberslineup.Thecasingshoewillbeabout
30’TVDbelowthebaseofthedisposalzone.ItwillbeageologicalpicknotaTVDstoppoint.Iattachedthecross
sectionsoyoucanseethevariability.
Regards,
Sean
3
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Wednesday,June14,20231:59PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
HiSean,
Perthedepthsyouprovidedinyouremailbelow,thesurfacecasingshoea5327’MDwillfallwithinthedisposal
interval.OramImissingsomething?
Thanks,
SteveDavies
AOGCC
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
4
From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Sent:Wednesday,June14,20239:43AM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
Steve,
AͲ18ProjectedTopDisposal
MD:5,148’
TVD:3,333’
AͲ18ProjectedBaseDisposal
MD:5,387’
TVD:3,449’
TheplanistosetsurfacecasingtofullyisolatethedisposalzoneandstayabovetheSterlingXat3508’TVD.Pleasekeep
inmindthatthesedepthsareprojections.WewillhavethetownGeologistwatchingandcallingthecasingpickviareal
timelogs.Thetwostagecementjobisdesignedtoisolatethedisposalzoneandfullycementtosurface.
Regards,
sean
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,June13,20232:48PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestions
Sean,
Afewmorequestions:
WherewillthetopandthebaseofthedisposalzonedefinedinAͲ12beinlocatedinAͲ18(MDandTVD)?
I’massumingthatthesurfacecasingandcementaredesignedtoisolatethisdisposalzoneinAͲ18andthatageologist
willbeonsitetopickthiscasingpoint,correct?
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5
Thanksandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission
(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use
ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding
it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.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.
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.
1
Davies, Stephen F (OGC)
Subject:FW: [EXTERNAL] RE: NCIU_A-18 (PTD #223-033) - Question
From:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Sent:Tuesday,June13,20231:38PM
To:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestion
HiSteve,
Sorryittooksolongtogetbacktoyou,IwaswaitingondatabackfromourGeologist.Thankyouforcatchingthiserror.TheGeoandIhaddifferentwellplan
#5s.Wefoundadataissuebetweenourdirectionalplannerandthedirectionalcompany.InadditiontofixingtheMDswealsotweakedtheTVDstobetterfit
whatmightbeseenduringthesidetrack.IhaveattachedtheGeocrossͲsectionthatwasusedforthecasingpick.
Thepressuregradientsareaccurate.ThisissimilartowhatwedrilledinAͲ12lastyear.
Regards,
sean
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2
3
From:Davies,StephenF(OGC)<steve.davies@alaska.gov>
Sent:Tuesday,June13,20231:17PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:[EXTERNAL]RE:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestion
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
4
HiSean,
I’mfollowinguponmyemailbelowregardingtheTVDandestimatedpressuresinAͲ18.IcanfillintheproperTVDs.Aretheanticipatedpressuregradient
valuesof0.431and0.520accurate?
Thanks,
SteveDavies
AOGCC
From:Davies,StephenF(OGC)
Sent:Saturday,June10,202312:21PM
To:SeanMcLaughlin<Sean.Mclaughlin@hilcorp.com>
Subject:NCIU_AͲ18(PTD#223Ͳ033)ͲQuestion
HiSean,
I’mreviewingthePermittoDrillapplicationforAͲ18.CouldyoupleasechecktheTVDandestimatedpressurevaluesontheMASPcalculationsheetandprovide
acorrectedcopyifneeded?
Forexample,fortheBelugaHbottomat7720’MD,thetableprovidesaTVDof5542’,butthedirectionalsurveyindicatestheTVDshouldbeabout4781’.
5
Thanksandstaysafe,
SteveDavies
AOGCC
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission(AOGCC),StateofAlaskaandisforthesoleuseofthe
intendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲ
mail,pleasedeleteit,withoutfirstsavingorforwardingit,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:Sean McLaughlin
To:McLellan, Bryan J (OGC); Dan Marlowe
Cc:Ryan Rupert; Aras Worthington; Monty Myers
Subject:RE: [EXTERNAL] NCIU A-17 PTD questions
Date:Tuesday, June 13, 2023 1:46:37 PM
Attachments:image001.jpg
Yes, Please. I agree as well.
Can you make the same change to A-18 or would you like me to resubmit the PTD?
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, June 13, 2023 1:36 PM
To: Dan Marlowe <dmarlowe@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Dan,
I’m in agreement.
Sean, are you on board with a 3000 psi MITIA test pressure? Should I modify the PTD accordingly?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Dan Marlowe <dmarlowe@hilcorp.com>
Sent: Monday, June 12, 2023 10:00 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
It should be tested to above MPSP, in this case 3,000 psi.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, June 12, 2023 9:21 AM
To: Dan Marlowe <dmarlowe@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Dan,
What do you believe to be an appropriate initial MIT-IA test pressure for this new well and what is
the reasoning?
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Dan Marlowe <dmarlowe@hilcorp.com>
Sent: Friday, June 9, 2023 1:28 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan
As you know, the calculated drilling MPSP at 2,940 psi. This is our worst case scenario on Tyonek . All
other production or injection MPSP’s fall below drilling MPSP.
Artificial lift on Tyonek is ~1,000 psi so anything in the 1,250 to 1,500 psi range addresses lift
pressure.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Injectors on Tyonek are fairly shallow and are tested to 0.25 psi/ft or 1,500 psi whichever is greater
per regulation:
A-08 has an MIT-IA to 1,500 psi
A-13 has an MIT-IA to 2,500 psi
All wells have daily casing pressure monitoring with a backup report that flags any variance above
10% to town staff. We also have procedures in place that document any bleed events that occur.
Thanks
Dan
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, May 30, 2023 10:00 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Monty Myers <mmyers@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Sean,
The relevant regulations for pressure testing in producing wells are:
During well construction, 20 AAC 25.030(d)(6) Test liner lap to 50% of casing burst, same as
the casing test, for any well type. The A-17 PTD application does not include a plan to test the
liner lap to 50% of surface casing burst.
As you sited below, injectors have a specific MITIA test pressure requirement, not relevant to
A-17.
During the producing phase, 20 AAC 25.205(d) Regulation is silent on the value of the test
pressure, so we are looking for an engineering basis for test pressure here. The premise is
that you should test to at least as high as you anticipate seeing the pressure throughout the
life of the well. Need to consider the pressure the well might see at any depth from the
wellhead down to the liner lap or packer. In the absence of other justification, we simply test
to Max Potential Surface Pressure (MPSP) calculated using reservoir pressure minus a gas
gradient of 0.1 psi/ft, but also need to look at potential artificial lift pressures that might be
imposed. Unfortunately, testing the wellhead to this pressure over a column of mud might
impose a test pressure at the packer that is higher than necessary.
Dan,
The reason I brought the OE into this conversation is that the life-of-well pressures are more a
production issue than a drilling issue. If Hilcorp wants to test to something lower than MPSP, then
possibly they can justify it with wellhead pressure monitoring and bleed protocol, or something else.
Can Hilcorp create a minimum MITIA test pressure basis for the different types of wells on the
platform, and get buyoff from AOGCC, so that we are all on the same page whenever a new PTD is
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
submitted? The drilling pressure test basis might be higher, but would need to be calculated on a
well-by-well basis, but at least we would know the minimum from a production standpoint.
Thanks and regards
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: Friday, May 26, 2023 2:59 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
For and existing well on Tyonek a 1500 psi IA test is well above MASP and gas lift pressure. Also,
while it really doesn’t apply, a 1500 psi test fits 20 AAC 25.412c.
For a new drill the casing will be tested to ~50% at least 50% of casing burst and be above MASP for
that hole section and initial production. In the case of A-17 that is a 3500 psi casing test.
Could you help me find which regulation states that an IA test is required after running tubing in a
new drill? A Tubing test shows one envelope and Casing test shows the other. Is a MIT-IA required
after running the tubing? I thought I knew the regulation but now can’t find it.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 26, 2023 2:07 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
What’s the basis for the 1500 psi test pressure?
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: Friday, May 26, 2023 2:04 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: RE: [EXTERNAL] NCIU A-17 PTD questions
Bryan,
Please continue to route questions through me so I can get to the right person and there is a clear
line of communication for PTD’s.
Ryan Rupert is the Offshore Ops engineer and we have already conferred about the necessary
mechanical integrity for A-17. 1500 psi would be a usual IA test for Tyonek wells. Take B-03A, which
was drilled last year, as an example. It currently has a BHP of 380 psi. The casing and wellhead is
tested to 3500 psi after installation. After the liner run, the liner lap and seal test to 2000 psi would
show sufficient integrity for those components. The tubing hanger is tested with a 3000 psi pack off
test.
Regards,
sean
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Tuesday, May 23, 2023 3:53 PM
To: Ryan Rupert <Ryan.Rupert@hilcorp.com>
Subject: FW: [EXTERNAL] NCIU A-17 PTD questions
Ryan,
Do you want to answer Bryan’s question for him. Let me know if you want to chat about it.
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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Tuesday, May 23, 2023 3:39 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: FW: [EXTERNAL] NCIU A-17 PTD questions
Chad,
What do you test the MIT-IA’s to on Tyonek and what is the basis? See question 8 in the email
below.
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: Sunday, May 21, 2023 9:34 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Re: [EXTERNAL] NCIU A-17 PTD questions
Correction/typo on #8. GL pressure is around 1000 psi. Not 100 psi.
Sean
On May 19, 2023, at 4:21 PM, Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
wrote:
Bryan,
Please find answers in red below.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, May 19, 2023 1:36 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A-17 PTD questions
Sean,
A few questions regarding the PTD application.
1. Could you send a proposed wellbore diagram with higher resolution? Some of
the numbers are illegible.
Attached
2. Is it possible to pressure test your diverter/conductor before you start drilling?
The equipment does not have the ability to test the diverter/conductor.
3. Need more justification for leaving Close approach failure wells on line while
drilling past them.
It is fortunate that so many great mitigations are available for these close
approaches (Bit selection, Gyro shots, Annuli monitoring, and multiple casing
strings). In fact, it would be more of a hazards to mobilize wireline, RU
lubricator, set plug, PT, then have a second rig up to pull the plug.
4. What is the depth and reservoir pressure of the injection zone just above surface
casing TD?
The top disposal zone is at 3307’ TVD and the bottom is at 3415’ TVD. The
shut-in WHP of the injection string in B-01 is 0 psi, so assuming a water
gradient of 0.43 psi/ft to 3307’ = 1422 psi.
5. Could you send the product specs for 12 ppg EconoCem?
Halliburton hasn’t loaded or tested for this job so no UCA or TT data available.
Below is the properties we ask for:
<image006.png>
6. How will your wellhead be configured after cementing surface casing and
moving to NCIU A-18? Send a diagram.
A blind flange is nippled up to the wellhead and a gate valve on the side outlet
for monitoring. I’ll see if Cactus can make a drawing on Monday.
<image002.png>
7. 4-1/2” liner cement job calculation uses 1.4 x excess, but text in step 19.6 calls
for 1.5 times excess.
40% excess in the calculation is correct.
8. What is the basis for the 2000 psi MITIA after running tubing? What is max gas
lift header pressure?
2000 psi is what the liner top will be tested to based on the following:
1. 10.1 ppg mud and 2000 psi @ 3420’ TVD = 178klbs force on the
4-1/2” liner (62%)
2. 2000 psi and 10.1 ppg mug equates to 21.3 ppg EWM
The 2000 psi MITIA was a consistent value to the liner top test and shows
tie back seal integrity. The casing and wellhead was tested to 3500 psi in
step 14.3.
Tyonek gas lift pressure runs around 100 psi.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
<image001.jpg>
<NCI A-17 Proposed Schematic 3-21-23.pdf>
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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.
NCIU A-18
NORTH COOK INLET UNIT
223-033
TERTIARY SYSTEM GAS
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:N COOK INLET UNIT A-18
Initial Class/Type DEV / PEND GeoArea 820 Unit 11450 On/Off Shore On
Program DEVField & Pool Well bore seg
Annular DisposalPTD#:2230330
NORTH COOK INLET, TERTIARY GAS - 564570
NA1 Permit fee attached
Yes Surface Location lies within ADL0017589; Top Prod Int & TD lie within ADL0037831.2 Lease number appropriate
Yes3 Unique well name and number
Yes NORTH COOK INLET, TERTIARY SYSTEM GAS POOL – 564570, governed by CO 68A issued 2020-04-204 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
Yes6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
NA15 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 provided
Yes19 Surface casing protects all known USDWs
Yes Two stage surface casing cement20 CMT vol adequate to circulate on conductor & surf csg
Yes21 CMT vol adequate to tie-in long string to surf csg
Yes22 CMT will cover all known productive horizons
Yes23 Casing designs adequate for C, T, B & permafrost
Yes24 Adequate tankage or reserve pit
NA25 If a re-drill, has a 10-403 for abandonment been approved
No Close approach just below conductor. Offset well is disposal injector that will be shut-in while drilling by.26 Adequate wellbore separation proposed
Yes27 If diverter required, does it meet regulations
Yes28 Drilling fluid program schematic & equip list adequate
Yes29 BOPEs, do they meet regulation
Yes MPSP = 2989 psi. BOP rated to 5k psi (BOP test to 3500 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 shutdown
No33 Is presence of H2S gas probable
NA34 Mechanical condition of wells within AOR verified (For service well only)
Yes None anticipated.35 Permit can be issued w/o hydrogen sulfide measures
Yes Expected Pressure Range is 0.425 to 0.52 psi/ft (8.2 to 10 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zones
NA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zones
NA Some potential for drilling depleted sands; LCM will be available onsite.38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
SFD
Date
6/12/2023
Appr
BJM
Date
6/28/2023
Appr
SFD
Date
6/13/2023
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
