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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 6/26/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240626
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
KU 33-08 50133207180000 2224008 5/4/2024
YELLOW
JACKET SCBL
NCI A-12B (REVISED) 50883200320200 223053 5/2/2024 READ
Multi Array Production
Profile (MAPP)
PBU M-200 50029237120000 222031 6/4/2024 READ Production Profile
Revision Explanation: There are additional images added to the final report and a few new .las
files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and
POOH are new .las files
Please include current contact information if different from above.
T39049
T39050
T39051
224-008
Multi Array Production
NCI A-12B (REVISED)50883200320200 223053 5/2/2024 READ Profile (MAPP)
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.06.26 14:44:09 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/21/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240521
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
END 3-07A 50029219110100 198147 5/11/2024 HALLIBURTON Coilflag
MPU E-19 50029227460000 197037 3/25/2024 READ CaliperSurvey
MPU F-66A 50029226970100 196162 5/8/2024 READ CaliperSurvey
MPI 1-27 50029216930000 187009 5/7/2024 READ PPROF
MPU L-17 50029225390000 194169 5/8/2024 READ CaliperSurvey
NCI A-12B 50883200320200 223053 5/2/2024 READ MAPP
NCI A-17 50883201880000 223031 5/3/2024 READ MAPP
PBU 11-41 50029237820000 224017 5/11/2024 HALLIBURTON RBT/Coilflag
PBU D-31B 50029226720200 212168 5/12/2024 HALLIBURTON RBT
PBU F-31A 50029216470100 212002 5/8/2024 READ CaliperSurvey
PBU J-19 50029216290000 186135 5/2/2024 HALLIBURTON RBT
PBU L-292 50029237510000 223025 5/6/2024 HALLIBURTON PPROF
Please include current contact information if different from above.
T38831
T38832
T38833
T38834
T38835
T38836
T38837
T38838
T38839
T38840
T38841
T38842
NCI A-12B 50883200320200 223053 5/2/2024 READ MAPP
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.22 09:57:50 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 3/15/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240315
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut
BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf
BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP
BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF
BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf
GP ST 18742 37 (AN-
37) 50733203940000 187109 11/22/2023 AK E-LINE Perf
KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF
KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch
PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch
NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT
NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT
NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf
SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE
GPT-Cmnt-CIBP-
Perf
Please include current contact information if different from above.
T38630
T38630
T38631
T38632
T38633
T38634
T38635
T38636
T38637
T38638
T38639
T38640
T38641
NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.18 08:49:06 -08'00'
You don't often get email from kkozub@hilcorp.com. Learn why this is important
From:Brooks, Phoebe L (OGC)
To:Karson Kozub
Cc:Regg, James B (OGC)
Subject:RE: [EXTERNAL] RE: SLB 1 11-30-23
Date:Tuesday, January 9, 2024 8:52:39 AM
Attachments:Schlumberger 1 11-30-23 Revised.xlsx
Thank you for the explanation and email. I’ve attached a revised report to include these updates and
additional remarks. Please update your copy.
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Karson Kozub <kkozub@hilcorp.com>
Sent: Tuesday, January 9, 2024 6:57 AM
To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>
Subject: RE: [EXTERNAL] RE: SLB 1 11-30-23
Good Morning Phoebe,
The Nitgn. Bottles should be NA, thank you for catching that.
On this well campaign we had approval to test BOPE’s every seven days on a 3 well campaign. The
form submitted was for one weekly BOPE test of the campaign. Attached is an email between
Hilcorp and the AOGCC for reference. I should have attached the approval on the original email.
Please let me know if you would like any other updates to the form.
Karson Kozub
Hilcorp Alaska, LLC.
Mobile: 907-570-1801
From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Sent: Monday, January 8, 2024 12:18 PM
To: Karson Kozub <kkozub@hilcorp.com>
Cc: Regg, James B (OGC) <jim.regg@alaska.gov>
Subject: [EXTERNAL] RE: SLB 1 11-30-23
1RUWK&RRN,QOHW$%
37'
revised repor
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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Karson,
The Nitgn. Bottles field was left blank; should this be “NA”? Also, the remarks referenced three wells
– if BOPE test were conducted on all wells, a separate report is needed for each. Please advise.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Karson Kozub <kkozub@hilcorp.com>
Sent: Friday, December 1, 2023 7:06 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay
<doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Juanita Lovett <jlovett@hilcorp.com>
Subject: SLB 1 11-30-23
Attached is the BOPE test form for SLB CTU #1 on 11/30/2023.
Karson Kozub
Hilcorp Alaska, LLC.
Mobile: 907-570-1801
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
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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
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STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmit to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:1 DATE: 11/30/23
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230530 Sundry #323-626
Operation: Drilling: Workover: X Explor.:
Test: Initial: Weekly: X Bi-Weekly: Other:
Rams:250/3500 Annular:N/A Valves:250/3500 MASP:2892
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 0NA
Permit On Location P Hazard Sec.NA Lower Kelly 0NA
Standing Order Posted P Misc.NA Ball Type 0NA
Test Fluid Water Inside BOP 0NA
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 1 1.75" Top Load P Trip Tank NA NA
Annular Preventer 0NAPit Level Indicators NA NA
#1 Rams 1 1.75" Blind/Shear P Flow Indicator NA NA
#2 Rams 1 1.75" Pipe/Slip P Meth Gas Detector NA NA
#3 Rams 0NAH2S Gas Detector NA NA
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 2 2" 2x2 FMC P Time/Pressure Test Result
HCR Valves 0NASystem Pressure (psi)2900 P
Kill Line Valves 2 2" 2x2 FMC P Pressure After Closure (psi)2150 P
Check Valve 1 2" FMC P 200 psi Attained (sec)29 P
BOP Misc 2 EQ Ports P Full Pressure Attained (sec)82 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):NA
No. Valves 5P ACC Misc 0NA
Manual Chokes 2P
Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 0 NA
#1 Rams 18 P
Coiled Tubing Only:#2 Rams 13 P
Inside Reel valves 1P #3 Rams 0 NA
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:2.0 HCR Choke 0 NA
Repair or replacement of equipment will be made within days. HCR Kill 0 NA
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 11/29/23 7:54hrs
Waived By
Test Start Date/Time:11/30/2023 17:00
(date) (time)Witness
Test Finish Date/Time:11/30/2023 19:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Jim Regg
SLB
SLB CT1 BOPE testing weekly instead of on each well for NCIU "Tyonek" wells A-12B (PTD 2230530), A-17 (PTD 2230310), and
A-18 (PTD 2230330) per AOGCC approval email dated 11/22/23.
Bryson Lowe
Hilcorp
Karson Kozub
NCIU A-12B
Test Pressure (psi):
Blowe2@slb.com
kkozub@hilcorp.com
Form 10-424 (Revised 08/2022) 2023-1130_BOP_Schlumberger1_NCIU_A-12B
$ODVND//&
9 9 9
999
9
9
9
9
9
MEU
-5HJJ
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): North Cook Inlet Unit
GL:N/A BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 101 (ft MSL)
22. Logs Obtained:
23.
BOTTOM
9-5/8" L-80 3,427'
4-1/2" L-80 6,964'
4-1/2" L-80 3,302'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
Surface 3,341
3,300'
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
TUBING RECORD
Tieback Assy.Tieback
8-1/2"
L - 220 sx / T - 236 sx
3,267' L - 650 sx / T - 181 sx
Surface
7,517'
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
331994 2586723
50-883-20032-02-00October 31, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
12/7/2023 223-053 / 323-626
N/A
NCIU A-12BNovember 9, 20231254' FNL, 928' FWL, Sec 6, T11N, R9W, SM, AK
126.6
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2587458
SETTING DEPTH TVD
2587598
TOP HOLE SIZE
CBL 12-1-23, LWD (DGR, PWD, ADR, DDSR) GPT / Perf Tie In Logs
Tertiary System Gas Pool
ADL 17589 / ADL 37931
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
330388
330095
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
12-1/4"
N/A
2,640' MD / 2,639' TVD
463' / 463'
7,519' MD / 6,966' TVD
7,434' MD / 6,884' TVD
545' FNL, 641' FEL, Sec 1, T11N, R10W, SM, AK
410' FNL, 937' FEL, Sec 1, T11N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6# Surface
47#
12.6#
3,494'
Water-Bbl:
PRODUCTION TEST
12/8/2023
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
011457 1002
12/22/2023 24
Flow Tubing
1
6989
N/A69890
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 8:32 am, Jan 03, 2024
Completed
12/7/2023
JSB
RBDMS JSB 010924
GDSR-1/29/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel M1 6,345' 5,839'
3547' 3473;
4743' 4455'
5864' 5395'
5990' 5508'
6105' 5613'
6192' 5694'
6308' 5803'
6385' 5878'
6438' 5929'
6484' 5973'
6569' 6055'
6834' 6310'
7270' 6727'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
INSTRUCTIONS
Bel U
Bel L
Bel M
Bel P
Bel Q
Bel S
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt Report.
Authorized Title: Drilling Manager
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Bel O
Bel J
Sterling X
Bel K
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Bel N
Bel A
TPI (Top of Producing Interval).
Authorized Name and
Bel I
Formation Name at TD:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
01/02/24
Monty M
Myers
Updated By: JLL 12/22/23
SCHEMATIC
North Cook Inlet Unit
Well: NCIUA-12B
PTD: 223-053
API: 50-883-20032-02-00
Casing Detail
Size Wt Grade Conn ID Top Btm
30”133 H-40 Welded 28.000 Surf 381’
20”133 H-40 19.730 Surf 1,990’
13-3/8”72 N-80 BTC 12.347 Surf 2,640’
9-5/8”47 L-80 TXP 8.681 Surf 3,494’
4-1/2”12.6 L-80 TXP 3.958 3,300’7,517’
Tubing Detail
4-1/2”12.6 L-80 Hyd 533 3.958 Surf 3,341’
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 1,956’1,956’3.833 SFO-1 16 Dome
2 3,226’3,202’3.833 SFO-1 24 Orifice
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)
ID Item
66.60’66.60’Hanger
1 463’463’3.813 Giant Oil Tools TR-SCSSSV
2 3,282’3,251’3.813 X Nipple 3.813” Profile
3 3,300’3,267’7.375 Liner hanger / LTP Assembly
4 3,332’3,294’3.870 Seal Stem
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
M1 6,345’6,365’5,839’5,858’20’12/08/23 Open
O1 6,449’6,459’5,939’5,949’10’12/07/23 Open
Q3 6,692’6,715’6,173’6,195’23’12/07/23 Open
Q4 6,719’6,733’6,199’6,212’14’12/07/23 Open
S2 6,958’6,978’6,428’6,447’20’12/07/23 Open
Note:
5,517’RA Marker
6,519’RA Marker
Cement Details
9-5/8"12-1/4" Hole: Pumped 93 bbls of 12.0ppg lead cement followed by 48 bbls of 15.8ppg tail cement. 8 bbls lost
during job. Assuming 30% openhole washout, volumetric ToC = 1,550’ MD
4-1/2”8.5” hole: Pumped 260 bbls of 12.0ppg lead cement followed by 37 bbls of 15.3ppg tail cement. 40bbls cement
circulated back to surface from liner top.ToC = 3,340’MD.(CBL 12/1/23)
Activity Date Ops Summary
4/14/2023 Mobe crews on boat to Grayling platform due to weather hold with choppers.,Breakdown rig, load derrick, carrier & beam package on boat with crew.,Send load to
Tyonk platform, orientate crew & PJSM.,unload boat & put beam package together, spot base beams on package to well center. install carrier & install walkways.
4/15/2023 Cont. install landings, "A" leg, & Derrick. rest crew on Tyonek send boat to Grayling for 2nd load, guys prep loads & clean decks, Backload boat w/ rig Eq., send
boat to Steelhead p/u rig jacks send boat to Tyonek. Mobe out remaining crew members from beach and move crew from Grayling to Tyonek.,Orientate crews to
Tyonek, PJSM, unload jacke from boat & r/u same, skid rig to A-12A well center, secure same, continue unload boat spotting eq. R/U circulating lines f/pits to
pump. prep derrick & stand, string up drill line. arrange deck, prep loads for backload, send boat to Grayling t/p/u last load of rig Eq.
4/16/2023 Continue stringing up lines in Derrick, l/d same, R/U companion flanges to wellhead & run circulating lines to take returns to production. Boat loading last of rig eq.
from Grayling.,Circulate hole STS volume till clean (450bbls) to production w/drill water, 3.3BPM 200 psi, cont. prep backload for boat.,S/D & monitor well static,
set BPV, N/D tree, prep wellhead, install blanking sub. N/U BOPE tq flanges, check accumulator bottle pre-charge, R/U test pump,Spot Accumulator, run lines,
set electrical distribution panel, R/U prep, stand & raise derrick, secure same.,Install rig floor, stairs & landings, tarp in cellar, m/u 4 1/2" test joint, function test
BOPE
4/17/2023 Cont. Function test BOPE, replace fitting on accumulator line, re-test good.,Fill surface BOPE with water, attempt shell test w/ 4 1/2" TJ on variable pipe rams
having leak on low test, run high test 2500 psi good, Tropubleshoot low test leak, chase down to rams leaking. Shell test w/ annular 250/2500 good.,Source
replacement rams from beach, pull rams & cont. arranging deck & working on rig-up punch list.,Recieve replacement rams, 4 1/2'solid body, dress rams & install,
re-fill surface eq. w/ test water.,Test BOPE as per Hilcorp & AOGCC expectations. Witness waived by Jim Regg 4-17, test w/4 1/2" TJ, 250/2500 good, test gas
alarms & pvt.,Blow down equipment, pull and lay down test joint, break down test joint, rig up bails and elevators, loosen guy lines and remove turn buckles under
carrier, level rig and center elevators over BOPE, install turn buckles under carrier. Remove flow line valve on circulating head. And install circulating head on top
of annular. Remove off driller side stairs, raise rig floor, center BOPE stack with floor hatch, install,off drillers side stairs, Rig up McCoy tongs, offloading
Halliburton equipment. and spotting on deck rigging up same,Lubricate rig, complete Derrick inspection..,Finish rigging up floor, securing ladders and stairs.,Pull
back pressure valve.,Monitor well (well static),Back out lock down pins, make up landing joint into hanger, pull hanger at 40K to rig floor, break and lay down
hanger.,Pooh with 4-1/2 tbg racking backing in derrick t/ 833'
4/18/2023 Cont. POOH standing back 4 1/2" Kill string.,M/U CMT stinger BHA - 4 1/2" pup joint, XO, 2- joints 2 7/8" IBT tubing, mule shoe.= 70.25',TIH w/ 4 1/2" tubing from
derrick t/2893', up /dn wt 47k, cont in hole tag @ 2921', P/U 3' off tag depth.,R/U Halliburton Cmt eq. & pump lines, PJSM,Fill lines w/5 bbls water, PT cmt lines
760/2748 psi, good,,Mix & pump 24bbls 12PPG cmt@ 4bpm, 115psi, displace same rate 40 bbls drill water. full displacement from job.,R/D circ. line POOH
30'min up t/2545',,Rev circulate 1.5 tubing volume clean, R/U beaver slide.,POOH l/d 4 1/2" tubing.,Lay down cement stinger assemply,Make up hanger to landing
joint land hanger run in lock downs, BPV set, clear rig floor of handling equipment and tools, remove beaver slide, stairs & landings, remove rig floor. prep to
scope derrick down.,Scope down derrick & lay over, secure lines.,Nipple Down BOPE, down stack annular, double gate & mud cross.
4/19/2023 Cont. N/D, pull riser & spacer spool,N/U dry hole tree, test void 5k, test tree 300/5k good, Pull TWC, install tree cap.
4/24/2023 R/U Test CMT plug @ 2918' up ~134' Pressure up t/ 1646psi w/2.9bbls, 15 min 1629psi, 30 min 1622psi, bleed back 2.2bbls, good test,R/U e-line RIH tag TOC
@ 2665' POOH R/D same.
5/19/2023 MIT down 13-3/8" casing against cement plug (no tubing). Inspector Kam St. John witnessed. Pressured up to 1624psi. Lost 5psi followed by 3 psi over 30
minutes. PASS.
n (LAT/LONG):
evation (RKB):
50-883-20032-01-00API #:
Well Name:
Field:
County/State:
NCIU A-12A
North Cook Inlet Unit
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
232-00373
$325,000
Job Name:232-00373 TY NCI A-12A Decomplete
Spud Date:
Page 1/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:10/28/2023 End Date:
Report Number
1
Report Start Date
10/27/2023
Report End Date
10/28/2023
Operation
Finish L/D 20 more stands of DP. Skid rig 3’. Prep & Extend cantilever out over well 7’. Had to modify platform handrails a nd stairways. N/D A-12B Dry hole tree. Set
Riser in place. Replace ST-80 Torque cylinder that was leaking.
Lift & Set bops on riser. Start to torque bolts on BOPs and riser. Merica scafold hand install and inspect scafold heat structur after move.
Torque 2 connections on riser. Change out Lower pipe rams to 9 5/8", Install bell nipple and dresser sleave. Install and tighte n down bell inpple to flow box. Assist welder
with return ditch modifications.
Report Number
2
Report Start Date
10/28/2023
Report End Date
10/29/2023
Operation
Work on rig acceptance check list. Clean and organize well bay, Deck and rig floor from N/U. Install elbow 90 to drop returns into shaker ditch. Install flow ditch hole
plates. Inspect top drive saver sub
Install pup jt in rotary and change out saver sub. redress die blocks with new bolts. Trouble shoot and re-time grabber box seq uence.
Report Number
3
Report Start Date
10/29/2023
Report End Date
10/30/2023
Operation
Cont. trouble shooting and going through hydraulic timing sequence on pipe handler.
Rig up to test BOP's. Attemted a shell test finding 2 leaks on riser connection. Bled down pressure and re-torqued.
Test 13 5/8' BOP's as per sundry 250/3000 for 5 min each with 4.5" test jt. Pulled test jt and test blinds. Tested all gas and PVT alarms.
Swap out test jts to 9 5/8" and pressure test LPR 250/3000 for 5 min each.
Backed out L/D screw and pulled hanger to floor with test jt. and L/D same.
Make up jts of 4.5" and latch tool. RIH and latch onto isolation sleave.
Perform Draw down on koomey. Back out LDS and pull isolation sleave lay down same. Install wear ring and run in 4 LDS. POOH and L/D assebly.
Smelled diesel in stack and performed sheen test-failed. Pull bell nipple and replace rubber gasket and fixed leak. R/U on casi ng valve sucking out stack to production
flushing to remove top diesel.
Cont. to flush stack while bringing short pieces of BHA to rig floor. Discussing options with production for fluid disposal.
Hold PJSM, M/U 12 1/4" Bit, bit sub, watermelon mill and crossover. RIH with 3 stds of spiral 6 1/4" spiral drill collars to 28 8'.
Report Number
4
Report Start Date
10/30/2023
Report End Date
10/31/2023
Operation
P/U 21 Joints of 4.5 HWDP to 940'. P/U 10 Stands of 4.5 DP & Stand back 5 stands to make room. P/U another 10 Stands of DP to 2300'. Check torque with rig
tongs.
Rig up circ lines to production black water line from the trip tank. Rig up lines to ISO tanks . PJSM with production.
RIH & Wash down F/ 2609' T/ 2676'. Tag 40 k dn. Pump soap pill and chase with 9.1 PPG KCL mud sending returns to trip tank then to production. Displace until
interface at trip tank ( 340 BBL ). Shut down and pump down Trip tanks to production. Line up to ISO tanks & displace 100 BBL of soap/Mud interface. Shut down.
Pressure wash inside flow box. Sim-ops rig up to test CSG.
Line up and flood choke and kill lines and remove air from system. Pressure test CSG to 2301 PSI- good test. Bled down pressure and R/D testing equipment.
Flood flow ditches observing a leak on new 90 on starboard side and port side hole cover. Fixed 90 and starboard side leak and filled all sand traps at 400 GPM while
fixing port side cover.
Cont. working on leaks in flow ditches. Port side was fixed again but wasn't able to get good flow due to cuttings and old mud in ditch. Drilled 5' of CMT from 2676' T/2681'
400 GPM, 500 PSI, 70 RPM, 1-3K TQ, 2-5K WOB. Pickked up shut down rotary and pumps and set 50K Down.
Circulate 1.5X BU at 400 GPM, 500 PSI, while cleaning the port side ditch. Observed CMT cuttings at surface at BU and circulate d clean. Blow down all surface lines.
POOH F/2678' T/288' racking stds of DP and HWDP in derrick. Sim-ops cont. cleaning port side flow ditch.
Change out elevators, Rack back 3 stds of 6 1/4" spiral collars. Change out bails to short set.
Report Number
5
Report Start Date
10/31/2023
Report End Date
11/1/2023
Operation
Finish chg bails, and rig service
PJSM, P/up Well bore integrity 13-3/8" trackmaster whipstock assy.
RIH slow F/ 180' to 2626'
R/up ak e-eline and run chk shot w/ gryo X2 @ 116.24 AZ pooh. P/up single and oriente rih t/ 2656' and rerun gryo @ gyro TF = 3 37.02 or 164.51 ROHS. Pooh w/ wire
line
P/up stand rih t/ 2682' and set anchor w/good indacation of set @ 25k. and pull up hole to up weight + 5' and sheer bolt w/ 42k w/ top of whipstock @ 2640'
Obtain SPR and establish parameters. Mrill 13 3/8" window F/2640' -T/2645' , GPM- 720, PSI 1445, 70 RPM= 5-8K TQ, WOB= 5-9K. MW 9.1 – Vis 43,, P/U 120K, S/O
120K, ROT 120K.
Cont. Milling 13 3/8" window F/2645' -T/2656' , GPM- 825, PSI 1850, 70 RPM= 3-10K TQ, WOB= 8-10K. MW 9.1+ – Vis 47.
Report Number
6
Report Start Date
11/1/2023
Report End Date
11/2/2023
Operation
Cont. milling 13-3/8" window f/ 2656' t/ 2662' BOW mill formation t/ 2681'
dress and drift window with and without rotation ok
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151Permit to Drill (PTD) #:222098
Page 2/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Operation
Resume milling formation f/ 2681' t/ 2700' @ 830 gpm, 1950 psi, 80 rpm, w/ 3-6k TQ, 1-5k on mills w/ total Iron recovered of 746#
Pump 20 bbl high vis sweep around fallowed by 50 bbl LCM pill to up back ground concentrations while dressing window circ STS and balance mW @ 9.1 ppg w/ total
metal recovered @ 794#
R/up and Line up for F.I.T test. Purge air and clear lines. Preform F.I.T t/ 12.25 ppg EMW w/ 436 psi of applied pressure w/ 3 .1 bbls pumped and 1.6 bbls returned on
chart and graphed w/ no increases on any upper annulus noticed
Service rig repair leak on dresser sleeve of flow nipple. and off load and strap 9-5/8" csg
Pump dry job and POOH F/2623’ T/63’ racking back all HWDP and 6 ¼” DC.
L/D Whip stock tri-mill BHA #2 F/63’ T/Surface. Observed sever wear on starter mill and follow mill. Starter mill- 5/8” out, Follow mill- 5/8” out, Gauge mill- 1/16” out.
L/D Whip stock tri-mill BHA #2 F/63’ T/Surface. Observed sever wear on starter mill and follow mill. Starter mill- 5/8” out, Follow mill- 5/8” out, Gauge mill- 1/16” out.
Gather handling subs and xo’s for BHA, P/U mud motor to rig floor.
M/U 12 ¼” Kymera bit to motor. M/U DM, EDR and TM. Upload tools as per MWD. M/U xo, UBHO orient key set as per DD and gyro. M/U 2 flex collars xo and 4 stds of
HWDP W/jars T/445' and shallow hole test BHA
Report Number
7
Report Start Date
11/2/2023
Report End Date
11/3/2023
Operation
Finish p/up Bha and rih t/ 2629' monitoring displacement on trip tank ok
R/up AK E-line Rih w/ 1.80" gyro to chk TF @ 2629' pooh orient towards window run thru and exit window w/ no issues t/ 2692' and rerun gyro and orient
Wash f/ 2692' t/ btm @ 2700' Slide drill 12-1/4" directional hole and survey w/ gyro f/ 2700' t/ 3032'and acquired first clean survey and experiencing shakers blinding off
w/ silt
Cont. drilling 12 1/4" hole F/3032' T/3500' (3433' TVD) Total 468' (AROP 104') 650 GPM= 2100 PSI, 60 RPM= 2-3K TQ, WOB= 8-10K. MW in 9.1 – Vis 40, ECD= 9.3
PPG. Max Gas= 21 units, P/U 125K, S/O 115K, ROT 120K. Distance to plan- 34.39', 19.3' High, Right 28.47'
Circulate hole clean with 1.5x BU at 650 GPM, 1900 PSI, 60 RPM, 2K TQ while working pipe 60'.
Pump out the hole F/3500' T/2494', pull on elevators F/2694' T/2635' with no issues going through window.
RIH on elevators F/2635' T/3500' washing down last 60' tagging 15' of fill.
Pump Hi-vis flagged sweep around 650 GPM, 1900 PSI, 60 RPM, 2-3K TQ. Working pipe 60'. Sweep back on time with 20% increase in cuttings. Obtain SPR and flow
check well prior to POOH
POOH on elevators F/3500' T/2565', L/D single used for TD well. Observed porper displacement for trip. No issues pulling into w indow.
Report Number
8
Report Start Date
11/3/2023
Report End Date
11/4/2023
Operation
Service rig while moitoring static well
Pump dry job Pooh f/ 2565' t/ 96' Monitoring correct hole fill on trip tank ( Pulled wet)
Download MWD
Finish l/dn Bha bit graded PDC = 1-2-CT-S-X-I-NO-TD. Roller = 1-2-CT-G-1-I-BT-TD
Clean clear rig floor. Retrieve wear ring. R/up to run csg
PJSM w/ all involved on p/up and running csg
P/up flash light and M/up 9-5/8"float equipment and chk floats ok
Run 9 5/8", 47#, L-80 TXP casing F/126' T/1781' stopping at 1593' and circulate out old mud at 5 BPM, 168 PSI. PU 110K, SO 110K
Cont. Running 9 5/8", 47#, L-80 TXP casing F/1781' T/2607', At 2037' collars started to hangup in well head. Rigged up tugger line and pulled casing over for the collar to
pass.
Circulate out old mud at 5 BPM, 296 PSI. Prior to going out into open hole. Sim-ops install 6' bail extensions.
Cont. Running 9 5/8", 47#, L-80 TXP casing F/2607' T/2972' no issues going through window
Report Number
9
Report Start Date
11/4/2023
Report End Date
11/5/2023
Operation
Cont. Running 9 5/8", 47#, L-80 TXP casing F/2972' t/ 3489'
M/up circ swedge and circ btm up @ 6bpm @ 276 psi
Wash dn and work csg collars past well head f/ 3489' t/ tag of TD @ 3500' w/ 2' fill. Pooh l/dn three jts csg
P/up hanger and landing jts and land out w/ shoe 3493.70' up wt 210k and dn 170k. M/up cmt head and circ thru same and hold PJSM
Line up and cmt unit and pump 5 bbls water ahead @ 3 bpm at 90 psi. pressure test Low @ 575 psi and high @ 4500 psi good. Pump 60 bbls of 10.5 ppg spacer @ 4.3
bpm @210 psi launch btm plug fallowed by 93 bbls lead cmt @ 12.0 ppg and 48 bbls of tail cmt @ 15.8 ppg. launch top plug fallowed by 10 bbls water. rig displaced w/
mud @ 84 bbls in to displacement lost returns slowed rate t/ 1 bpm an regained returns and increase rate up to 3 bpm and bumped plug at cal volume and pressured up t/
1550 psi CIP @ 1635 hrs Bled off and chk floats ok Lost total of 8 bbls during job. R/dn cmt head and lines
R/D cement head and CMT line, Pull and breakdown landing jt. R/D Parker CSG equipment.
P/U a stand of 4.5" HWDP and M/U pack off to bottom. 5' in and land pack-off. RILDS as per vault rep and PT to 5000 PSI for 15 min-good test.
Clean out flow box. M/U 4.5" test jt and run test plug. Open lower pipe ram doors and change rams to 4.5" x 7" VBR. Close and tighten doors. Sim-ops assist welder with
replacing bolts on top dresser sleave of the bell nipple.
R/U test pump and fill stack, purge air from system. PT LPR's with 4.5" test jt 250/3000 PSI for 5/5. R/D test equipment and blow down kill line.
Pull bell nipple and dry off rubber, re-cilcone and tighten fixing leak.
Install wear ring and break down test jt assembly
Due to winds re-tying and tightening down weather tarps around rig and stack
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Page 3/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Report Number
10
Report Start Date
11/5/2023
Report End Date
11/6/2023
Operation
P/up and m/up triple combo drilling Bha #4 T/ 121'
Plug in and upload tools
M/up flex collars w/ 4-1/2" single of dp and preform surface test w/ 400 gpm @ 700 psi good. Brk out and rack back flex collar s
Hold PJSM for loading sources and load same
Rih F/ 121' t/ 3374' monitoring well on trip tank and tag cmt stringer
wash and ream and c/out cmt stringer f/ 3374' t/ tag of plugs @ 3405' @ 150 gpm @ 360 psi Up/DN/Rot 125/120/120
Test csg t/ 3866 psi w/ 4.3 bbls graft and charted for 30 min good test
Rig dn test equipment and aline valves for drilling operations
Grease and service valves on choke manifold and chg/out roll pin on CMV #18 and chg out shaker screen
Drill shoe track and 20’ of new hole T/3520’. 350 GPM, 975 PSI, 40 RPM, 3K TQ, PU 125K SO 120K, ROT 125K
Circulate hole clean at 350 GPM, 975 PSI, 40 RPM, 3K TQ.
R/U and perform FIT W/9.1 PPG to 14.8 EM- 1020 PSI, Pumped 1.7 BBLS- Bled back 1.5 BBLS.
Drill 8.5" Production Hole F/3520' -T/3635' Total 115' (AROP 38') 500 GPM= 1525 PSI, 40 RPM= 3K TQ, WOB= 3K. MW in 92 – Vis 41, ECD= 9.5 PPG. Max Gas= 22
units, P/U 125K, S/O 120K, ROT 125K. Double backream prior to connections
Cont. drilling 8.5" Production Hole F/3635' -T/3896' (3763' TVD) Total 261' (AROP 44') 500 GPM= 1600 PSI, 60 RPM= 2-4K TQ, WOB= 2-3K. MW in 9.1 – Vis 43, ECD=
9.4 PPG. Max Gas= 67 units, P/U 130K, S/O 125K, ROT 130K. Double backream prior to connections
Report Number
11
Report Start Date
11/6/2023
Report End Date
11/7/2023
Operation
Cont. drilling 8.5" Production Hole F/3896' -T/4187' Total 291' (AROP 48.5') 500 GPM= 1600 PSI, 60 RPM= 4-5K TQ, WOB= 2-3K. MW in 9.1+ – Vis 42, ECD= 9.4 PPG.
Max Gas= 32 units, P/U 130K, S/O 125K, ROT 130K. Double backream prior to connections Pump sweep around while drilling @ 4035' back on time w/ +20%
Cont. drilling 8.5" Production Hole F/4187' -T/4541' Total 354' (AROP 51') 500 GPM= 1725 PSI, 60 RPM= 4-5K TQ, WOB= 2-3K. MW in 9.1+ – Vis 43, ECD= 9.5 PPG.
Max Gas= 32 units, P/U 140K, S/O 130K, ROT 135K. Double backream prior to connections
Circulate hole clean 500 GPM, 1665 PSI, 60 RPM, 4K TQ working a full std.
Monitor well for 10 MIn- static. POOH F/4541' T/3426'. Observed proper displacement during trip.
Clean and clear rig floor from wet trip. Service top-drive and travelling blocks. Re-install stabbing board winch
RIH Back to BTM F/3426' T/4541' washing down last std tagging 11' of fill.
Resume drilling 8.5" Production Hole F/4541' -T/4819' (4515' TVD) Total 278' (AROP 43') 515 GPM= 1850 PSI, 60 RPM= 6-7K TQ, WOB= 2-4K. MW in 9.1 – Vis 43,
ECD= 9.5 PPG. Max Gas= 52 units, P/U 145K, S/O 135K, ROT 140K. Double backream prior to connections, Pumped a Hi-vis sweep @ 4541' back on time with 10%
increase in cuttings.
Report Number
12
Report Start Date
11/7/2023
Report End Date
11/8/2023
Operation
Continue drilling 8.5" directional Hole F/4819' -T/5100' Total 281' (AROP 46.8') 515 GPM= 1850 PSI, 60 RPM= 6-7K TQ, WOB= 2-4K . MW in 9.1 – Vis 43, ECD= 9.5
PPG. Max Gas= 85 units, P/U 145K, S/O 135K, ROT 140K. Double backream prior to connections, Pumped a Hi-vis sweep @ 5041' back on time with 20% increase in
cuttings. and mad passing slidws over 20'
Continue drilling 8.5" directional Hole F/5100' -T/5375' Total 275' (AROP 45.8') 515 GPM= 1850 PSI, 60 RPM= 6-7K TQ, WOB= 2-4K . MW in 9.1 – Vis 43, ECD= 9.5
PPG. Max Gas= 85 units, P/U 145K, S/O 135K, ROT 140K. Double backream prior to connections, Pumped a Hi-vis sweep @ 5041' back on time with 20% increase in
cuttings. and mad passing slidws over 20'
Continue drilling 8.5" directional Hole F/5375' -T/5550' Total 175'
(AROP 50') 500 GPM= 2050 PSI, 70 RPM= 8K TQ, WOB= 3K. MW in 9.4 – Vis 43, ECD= 9.8 PPG. Max Gas= 85 units, P/U 160K, S/O 140K, ROT 145K. Double
backream prior to connections, mad passing slidws over 20'
Circ BUS 500 GPM = 2050 PSI, 70 RPM= 6K TQ,
Monitor well for 10 MIn- static. POOH F/5550' T/4551'. Observed proper displacement during trip.
RIH to BTM F/4551' T/5550' washing down the last stand no fill observered.
Continue drilling 8.5" directional Hole F/5550' -T/5780' Total 230' (AROP 38.33') 500 GPM= 2190 PSI, 70 RPM= 8K TQ, WOB= 3-4K. MW in 9.6 – Vis 47, ECD= 10.10
PPG. Max Gas= 37 units, P/U 175K, S/O 145K, ROT 150K. Double backream prior to connections, mad passing slidws over 20'
Report Number
13
Report Start Date
11/8/2023
Report End Date
11/9/2023
Operation
Continue drilling 8.5" directional Hole F/5780' -T/6027' Total 247' (AROP 41.17') 498 GPM= 2350 PSI, 70 RPM= 8-9K TQ, WOB= 3-4K. MW in 9.9 – Vis 42, ECD= 10.35
PPG. Max Gas= 33 units, P/U 175K, S/O 145K, ROT 150K. Double backream prior to connections, mad passing slidws over 20'
Continue drilling 8.5" directional Hole F/6027'-T/6303' Total 276' (AROP 46') 498 GPM= 2350 PSI, 70 RPM= 8-9K TQ, WOB= 3-4K. MW in 10.2 – Vis 42, ECD= 10.51
PPG. Max Gas= 33 units, P/U 175K, S/O 145K, ROT 150K. Double backream prior to connections, mad passing slidws over 20' Pump sw eep around while drilling @
6083' back on time w/ 10% increase
Continue drilling 8.5" directional Hole F/6303'-T/6582' Total 279' (AROP 46.5') 480 GPM= 2500 PSI, 70 RPM= 8-9K TQ, WOB= 3-5K. MW in 10.2 – Vis 42, ECD= 10.71
PPG. Max Gas= 148 units, P/U 175K, S/O 145K, ROT 150K. Double backream prior to connections, mad passing slidws over 20' . Back ground gas has been 20-30
units with connection gas getting 130 units.
Circ BUS 480 GPM = 2400 PSI, 70 RPM= 8-9K TQ,
Monitor well for 10 MIn- static. POOH F/6582' T/5560'. Observed proper displacement during trip. tight spots were 20k-55k over pull @ 6280'-6240', 6170', 5903'-5870',
5818'-5800',5729'-5710'. worked on elevators till no over pull observered.
RIH to BTM F/5560' T/6582' washing down the last stand no fill observerd.
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Page 4/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Operation
Continue drilling 8.5" directional Hole F/6582'-T/6650' Total 68' (AROP 45.3') 480 GPM= 2480 PSI, 70 RPM= 8-9K TQ, WOB= 3K. MW in 10.2+ – Vis 49, ECD= 10.81
PPG. Max Gas= 377 units, P/U 185K, S/O 150K, ROT 165K. Double backream prior to connections, mad passing slides over 20'. Pumped 30bbl high vis sweep @ 6600'
came back on time with 20% increase at shakers. Back ground gas has been 20-30 units with connection gas getting 130 units, max trip gas was 377units .
Report Number
14
Report Start Date
11/9/2023
Report End Date
11/10/2023
Operation
Continue control drilling 8.5" directional Hole working off ECD F/6650'-T/6924' Total 274' (AROP 45.6') 480 GPM= 2600 PSI, 70 RPM= 10K TQ, WOB= 3K. MW in 10.3 –
Vis 49, ECD= 10.81 PPG. Max Gas= 370 units, P/U 185K, S/O 150K, ROT 165K. Double backream prior to connections, Back ground gas has been 20-30 units with
connection gas getting 130 units,
Continue control drilling 8.5" directional Hole working off ECD F/6924'-T/7139' Total 215' (AROP 35.8') 462 GPM= 2470 PSI, 70 RPM= 10.5K TQ, WOB= 3-6K. MW in
10.3 – Vis 47, ECD= 10.86 PPG. Max Gas= 293 units, P/U 185K, S/O 150K, ROT 165K. Double backream prior to connections, Back ground gas has been 20-30 units
with connection gas getting 130 units,
Continue control drilling 8.5" directional Hole working off ECD F/7139'-T/7399' Total 260' (AROP 43.3') 452 GPM= 2470 PSI, 70 RPM= 10.5K TQ, WOB= 3K. MW in 10.3
– Vis 53, ECD= 10.9 PPG. Max Gas= 174 units, P/U 195K, S/O 165K, ROT 170K. Double backream prior to connections, Back ground gas has been 20-30 units with
connection gas getting 100 units,
Continue control drilling 8.5" directional Hole working off ECD F/7399'-T/7519' Total 120' (AROP 21.8') 452 GPM= 2470 PSI, 70 RPM= 10.5K TQ, WOB= 3K. MW in 10.3
– Vis 53, ECD= 10.9 PPG. Max Gas= 48 units, P/U 200K, S/O 170K, ROT 180K. Double backream prior to connections, Back ground gas has been 20 units with
connection gas getting 25 units,
Pumped 30bbl high vis sweep @ 7455' 30% increase at the shakers and on time.
TD well @ 7519'MD and 6966' TVD as per geo
Report Number
15
Report Start Date
11/10/2023
Report End Date
11/11/2023
Operation
Circ BUS 450 GPM = 2500 PSI, 70 RPM= 8-9K TQ
Monitor well for 10 MIn- static. Attempt pooh on elevators 90k over w/ no movement. kelly up and broke circ and had rotate pipe free. Back ream OOH f/ 7519' t/ 6421'
seeing strong differential sticking with only pipe setting for a few minutes and working through tight spots @ 7504', 7445', 71 88', 6983', 6941', 6907', 6826', 6810', 6674',
6643'.
Continue back reaming ooh still experiencing differential sticking and working through tight spots f/ 6421' t/ 6028' 420 gpm @ 2300 psi w/ 60 rpm and 8-12k trq
Circ 2X btm up w/ very little cutting in returns and some large fist sized chunks of coal
Continue back reaming ooh experencing very little differential sticking But continuing working through tight spots f/ 6028' t/ 4970' 420 gpm @ 2300 psi w/ 60 rpm and
8-12k trq
Tried pulling pipe with out pumping or rotating unsuccesfully.
Attemepted to stage pumps up to back reaming rate of 420 gpm. Noticed no returns and that we lossed cIrcirculation and took tot al losses @ 4970' Pumped 30bbl LCM
pill @ 105gpm LCM pill in place @ 20:20. @ 20:30 was able to get returns to surface while pumping and filling from the top with the trip tank. (277bbl loss)
BROOH F/4970' T/ 4369' @ reduced GPM rate of 109gpm 220psi 70 RPM 7-15K TQ 130K ROT stageing in 2nd 30bbl 100PPG LCM pill.
Hung pipe up @ 4,369' was able to work pipe free and establish circulation.
BROOH F/4369' T/ 4333' @ reduced GPM rate of 109gpm 220psi 70 RPM 7-15K TQ stageing in 3RD 30bbl 100PPG LCM pill. Trip tank was swithched to FIW @ 01:30
POOH F/4333' T/ 3449' with no pumps rotating pipe only to stop swabbing 70 RPM 7-15K TQ Pumped a total of 60BBLS of FIW down the back side.
688BBL mud loss total for tour.
Displaced the 60BBLS of FIW on the backside with 10.3ppg mud after getting BHA into casing. With good mud in the hole established static loss rate of 45BPH loss rate.
Report Number
16
Report Start Date
11/11/2023
Report End Date
11/12/2023
Operation
Continue mointor static loss rate of 45BPH tapering off to 18 BPH loss rate. while building mud volume and servicing rig
Preform post jarring inspection while continue mointor well and building mud volume loss rate dn to 9 bph losses
Continue building mud volume while monitoring well on trip tank and Pump 10 bbls @ 1.5 bpm dn pipe to clear and warm surface li nes. intern increased our Loss rate t/
30 bbls
Spot 50 bbl LCM pill @ 100 ppb and clear pipe w/ 5 bbls @ 1.5 bpm @ 60 psi w/ partial returns during pumping
Blow dn TDS kelly hose, stand pipe to mud pumps and mointor losses trend on trip tank f/ 30>17.4 bph while continuing and finis hed building mud volume
Pooh slow and wet f/ 3454' t/ Bha @ 836'
Rack back HWDP and LD BHA #4 as per Halliburton rep
Clear and clean floor, PU test pump to rig floor, Drain stack, PU MU 4.5'' test jt to pull wear ring. BOLDS Pull wear ring, ins tall test plug. Fill up BOPE and Surface equip
for testing BOPE's. Build test jt. Install test sub on TD. Tested all gas and PVT alarms.
Test 13 5/8' BOP's as per sundry 250/3000 for 5 min each with 4.5" test jt. Pulled test jt and test blinds. Preformed accumulator drawdown test. Test witnessed by
AGOCC rep Guy Cook.
One Fail Pass on the audible alarm portion of the shaker LEL sensor it had to be recalibrated.
While testing BOPE monitored well on the trip tank minimal losses to the well 1/4bbl loss per hr.
RD test jt Equip. Drain stack. Install wear ring RILDS. BD Choke manifold. Remove test pump from the rig floor.
Report Number
17
Report Start Date
11/12/2023
Report End Date
11/13/2023
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Page 5/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Operation
Finish r/dn test equipment
Set wear ring and l/dn test jts
clear and clean rig floor
M/up 8-1/2" dumb iron clean out assy. continue working on building mud volume
Rih slow t/ 1031' w/ proper displacement kelly up and stage up pumps and attempt circ and warm mud @ 1.5 bpm @ 75 psi w/ only 40% returns lost 23 bbls on btm up
circ. Blow dn lines
Continue rih slow anything over 30FPM we were pushing fluid away. Rih slow keeping proper displacement f/ 1031' t/ 3432'. Work on building fibrous LCM pill and
rabbiting liner
Continue building mud volume, fibrous LCM pill, cleaning sand traps and rabbiting liner
Pump 62 bbl fibrous LCM pill @ 10.5 ppg and displace 5 bbls out of pipe @ 74 gpm @100 psi shut dn and let sink and soak
Pooh above pill @ 2302'
Break circ @ 88GPM working up to 525GPM @ 21GPM increments. Lost 38BBLS then gained full returns with no losses.
Cont'd building mud volume while circ the well @ 88gpm to keep the mud warm.
Cont'd building mud volume while circ the well @ 88gpm to keep the mud warm.
Report Number
18
Report Start Date
11/13/2023
Report End Date
11/14/2023
Operation
Cont'd building mud volume while circ the well @ 88gpm to keep the mud warm.
Dn pump and Blow dn lines Rih f/ 2302' t/ 3433' @ 60 fpm w/ proper displacement
Line up to catch possible returns of fibrous LCM pill in sand trap #1 while sending normal returns to pits. and stage up pump from 1 bpm @ 80 psi to 3 bpm @ 95 psi
due to loss rate 3bpm =18.6 bph and 2.5 = 6 bph loss rate and circ btm up and warm mud catching 60 bbls of returning mud w/ heavy fiber
Blow dn lines. Rih f/ 3433' t/ 3996' @ 60 FPH w/ no issues but noticed getting back just about Closed end displacement
Stage up pump rate t/ 2.5 bpm @110 psi while rotating and reciprocating pipe full std @ 70 rpm @ 4k TQ up/dn/rot 120/105/120k w/ no losses. Preformed a differential
test for 10 min and over pulled 10k
RIH f/ 3996' t/ 5005' Had set dn @ 4051', 4104' 4152' and unable to wash through and reamed tight spot clean t/ 4181' and rih clean t/ 5005' w/ no losses
Stage up pump rate t/ 3.5 bpm while rotating and reciprocating pipe full std w/ no losses. Circ hole clean and preformed a differential test for 10 min and over pulled 15k
RIH f/5005' t/6030' had set dn @ 5,208', 5,486', 5,535', 5,560', 5,612', 5,856' for all the tight spots rotated and washed thou gh with little effort, 70RPM, 5-7k TQ, 88GPM
150PSI no losses though all tight spots.
Stage up pump rate t/ 3.1 bpm 183PSI while rotating and reciprocating pipe full std w/ no losses till BUS slowed down pump rate to 2.5bpm and stoped loosing mud. Circ
hole clean and preformed a differential test for 10 min and over pulled 55k
RIH f/6030' t/6965' had set dn @ 6045', 6082, 61980', 6610', 6860' had to wash and ream 6042' and 6610' 70RPM, 5-7k TQ, 88GPM 150PSI no losses though all tight
spots.
Stage up pump rate t/ 4 bpm 256PSI while rotating and reciprocating pipe full std w/ no losses. Circ hole clean and preformed a differential test for 5 min and over pulled
20k
Report Number
19
Report Start Date
11/14/2023
Report End Date
11/15/2023
Operation
RIH f/6965' t/7519' wash and ream as needed wiping tight clean with minimal work ream last std to btm w/ 13' fill
Stage up pump rate t/ 3.5 bpm 240PSI while rotating and reciprocating pipe full std w/ 1 bph loss rate. fallowed by a 40 bbl high vis LCM sweep around w/ no losses
preformed a differential test for 5 min and over pulled 25k. up/dn/rot 200/145/175k 70 rpm @ 10k TQ flow chk static
Pooh on elevators f/ 7519' t/ 5377' w/ no issues and proper displacement
Pump weight LCM pill as a dry job @ 3 bpm 200 psi Dry job did not fall pooh wet
Continue Pooh on elevators wet f/ 5377' t/ 3337' w/ no issues
Blow dn surface lines and Mointor well while servicing rig well static no losses
POOH wet F/3337' T/98' Monitor well at the HWDP for 10 min well static
RIH with 2 stds of DC, LD DC and BHA #5
PU MU wear ring puller BOLDS pull wear ring. RU to run 4.5'' liner with Parker Casing Rep.
PU MU 4.5'' liner shoe track assy to make up spec as per tally. Test float equip good test. Run 4.5'' liner as per tally F/164 ' T/402'
Report Number
20
Report Start Date
11/15/2023
Report End Date
11/16/2023
Operation
Continue running 4.5'' TXP L-80 12.6# liner as per tally F/402' T/2043' displacement off appears to be about balance
Install head pin and circ well staging up pump rate t/ 2 bpm @ 86 psi checking mud weight in and out balanced well. While r/dn all rig floor sperry equipment and prep
same for boat
Resume running 4.5'' TXP L-80 12.6# liner as per tally F/2043' T/3491' filling each jt and monitoring well for proper displace ment
Install head pin and circ well staging up pump rate t/ 2 bpm @ 102 psi checking mud weight in and out balanced well. While waiting on boat and working same
Prep cement head for PU and use prior to entering open hole. Cont' to offload and backload M/V Titian
Resume running 4.5'' TXP L-80 12.6# liner as per tally F/3491' T/4165' filling each jt and monitoring well for proper displace ment
RD 4.5'' casing handling equip. PU RU 7'' handling equip to PU MU Baker seal bore extension, SLZXP packer hanger assy, and runn ing tool. PU MU Baker seal bore
extension, SLZXP packer hanger assy, and running tool as per Baker Rep. Run 4.5'' liner in the hole with 4.5'' DP F/4,165' T/4,417'.
Circ BUS while reciprcating pipe @ 2BPM 85PSI taking no losses to the well checking mud weight in and out balanced well. RD an d cleared the floor of 7'' handling
equip.
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Page 6/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Operation
Run 4.5'' liner in the hole with 4.5'' DP F/4,417' T/5250'.
Report Number
21
Report Start Date
11/16/2023
Report End Date
11/17/2023
Operation
Run 4.5'' liner in the hole with 4.5'' DP F/5,250' T/5,890'. Drifting out of the derrick w/ 2.375''.
Circ BUS while reciprcating pipe @ 5,890' 2BPM 125PSI PUW=130K SOW= 120K
Run 4.5'' liner in the hole with 4.5'' DP F/5,8' T/7,381'. Drifting out of the derrick w/ 2.375''.
Stage pumps up to 1.5BPM washing down F/7,321' T/7,519' Tagging bottom on depth no fill. PU RU Baker cement head.
Circ BUS while reciprcating pipe @7,519' staging up the pumps F/1.5bpm 200PSI T/5bpm 330PSI PUW=170K SOW= 145K
Held pre job safety meeting with HES on cementing liner. Blew air through all lines going to the cementers and flow back line. Hooked up and secured cement and flow
back lines to the cement head.
Pre Flush lines with 10BBLS of 8.4ppg water tested lines 640PSI low 4660PSI high. Followed by 30BBLS of 11ppg spacer. Pumped 260BBLS of 12ppg lead cement @
5BPM 310 PSI. Pumped 37BBLS of 15.30ppg tail cement @ 3BPM 153PSI. Shut in and washed down cement pumps to overboard line for 6mins. Dropped top liner dart
and HES chased with 10BBLS of 8.4ppg water @ 5BPM. DIsplaced well with rig pumps 93 bbls of 10.3ppg mud. Bumped plugs presured up to 1515psi. Bled off psi
getting .75bbl back to TT. Checked floats and they held. CIP @ 21:48 Calculated top of cement @ 3,321'
170K PUW 145K SOW Pulled up into tension @ 7517' and set SLZXP packer liner hanger as per Baker rep. Pressured up to 2500psi held for 2mins. Set down 90K to
ensure hanger set. Bumped up pressure to 3600psi held for 2mins to set packer and dogs. Dumped PSI to shear pins. Picked up to ensure we relaesed from hanger with
100K PUW free travel.
Washed out Seal bore extension to make sure no cement was trapped in it. Circ BUS to clear the 9 5/8'' casing of any cement ret urns above the packer. Over boarded
30bbls of spacer and 40bbls of cement.
Drained stack and flushed 2X with citric acid pill. BD all surface lines used for cement job.
RD cement head and XO's used to run it. RD circulating hoses and equip. While monitoring well on TT. DP U-Tubing
Circ well to balance well.
POOH F/3300' Racking back pipe due to high winds. BD high psi mud line back to the mud pits. CO pipe elevators to 5''. LD Bake r running tool
Report Number
22
Report Start Date
11/17/2023
Report End Date
11/18/2023
Operation
PU MU polish mill assy as per Baker rep. RIH on 4.5'' DP to 3,290'
Tag no go @ 3346' W/5K set down. TOL confirmed at 3,304'. Polish seal bore assy @ 3 BPM, 140 PSI, 30 RPM, 3K TQ, PUW=105K SOW=100K ROT=100K
Preformed liner lap assurance test @ 2217 psi for 10mins.
Displace well to FIW @ 7.2 BPM 500 PSI monitored and maintained BBLS in and BBLS out.
Empty lines to trip tank and flush lines with citric acid wash. Fill TT and BD high psi mud line back to the pumps
POOH LD 4.5'' DP F/ 3,290' to surface LD polish mill assy.
MU mule shoe on 4.5'' DP RIH T/2848'
Clear and prep rig floor for LD DP
LD 4.5'' DP F/2,848' to 1,300'
Report Number
23
Report Start Date
11/18/2023
Report End Date
11/19/2023
Operation
L/D 4.5DP f/1300' t/620'
Draw works motor brush failure, replace bent brush holder and c/o brushes. Simop- service rig, ready equipment for boat.
Cont. L/D 4.5"DP f/620' t/0',
RIH w/4.5"HWDP f/surface t/1500'.
Cont. L/D 4.5"DP/HWDP f/1500' t/surface.
Remove ST-80 from rig floor and placed in cradles for transport
RU to run 4.5'' TBG. MU casing swedge to TIW, pumping sub for the tbg and casing test.
Pre- job meeting for PU TBG. PU MU seal assy as per Baker rep.
Run 4.5''HYD 533 12.6# TQ= 4600 as per tally to 2,919'
Report Number
24
Report Start Date
11/19/2023
Report End Date
11/20/2023
Operation
P/U and RIH w/4.5"Hyd.533 12.6# L-80 tbg. as per tally f/2862'' t/3340, monitoring displacement on the TT.
Tag No-Go @ 3340' w/5k dwn. Space out- L/D 3 jt. and P/U 23' pups and hanger to land 2ft off No-go.
Terminate SSSV control line-test same t/5k w/Pollard/Vault Reps.. M/U landing jt. w/XO's. Attemt verify seals in seal bore by slacking off w/pumping 1.5bpm, 60psi and
landed hanger w/no pressure change. Seals are not in seal bore. Pull Hanger t/floor and re-calculate space out, excess control line hung in ram cavity and broke off, 4ft
control line fell into the annulus.
L/D landing jt, break off hanger and add 7.53' with 2 pups, (Hanger, hanger pup and XO pup were subtracted 2X). Splice control line and re-test t/5k -good.
Kelly up w/ landing jt. and wash down @2bpm, 60psi and cand caught pressure t/200psi. Shut off pumps and bled down pressure. Landed hanger @ 3338, 2ft off No-Go.
RILDS.
Rig up to test IA/Tubing t/3k for 30min. ea. on chart.
Test 4.5" 12.6# tbg t/3000psi f/30min. on chart, Pressure up IA/Tbg t/3000psi f/30min. on chart both test -good.
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Page 7/7
Well Name: NCIU A-12B
Report Printed: 12/20/2023www.peloton.com
Well Operations Summary
Operation
R/D test equipment, blow down all lines, R/d Parker casing and Pollard control line equipment. Pull landing jt..
Set BPV as per Vault rep
BD all surface lines and reverse water out of LJ and BOPE.
Start removing all studs and nuts but 4 per flanged connection on BOPE stack.
Clean out the polution pans and rotary pans under rig floor.
Cont'removing all studs and nuts but 4 per flanged connection on BOPE stack.
Clean out the polution pans and rotary pans under rig floor.
Back loaded M/V Titian with mud products rig equip and third party supplies.
Report Number
25
Report Start Date
11/20/2023
Report End Date
11/21/2023
Operation
Pull Bell and riser nipples and l/d same. CLear ice from bridge crane trolly winches
Remove rental rams from upper /lower ram cavities. Bridge cranes for BOP’s froze due to weather(air actuated), thaw same. Bled down and powered down Koomy.
Removed koomy lines from BOPE's. ND BOPE's. Simop-Pull centrifuge from rack and rig rack for back load. Load subs and chicksan into baskets for back load from rig
floor. Load handling tools from rig floor into basket for back load.
PU the lower riser section of the BOPE's and LD on upper pipe deck.
Assemble tree and orientate per Hilcorp Production rep torqueing all flanged connections . SIMOP Separating all valves and DSA 's off the mud cross. Prepping the to
traverse the drilling package. Disassemble scaffolding under
Started back loading boat until winds were too high to operate crane. Cont'd to prep rig for skidding off the Tyonek.
API: 5088320032 Field: North Cook Inlet Unit
Sundry #:
State: Alaska
Rig/Service: Spartan 151
Well Name: NCIU A-12B
API #:50883200320000 Field:North Cook Inlet Unit Start Date:11/30/2023
Permit #:169099 Sundry #:323-626 End Date:12/8/2023
11/30/2023
12/1/2023
12/2/2023
12/6/2023
12/7/2023
12/8/2023
Daily Operations:
RIH with gamma/pressure/temp tool. Observe fluid at 7,375’ (PBTD 7,425’). Bleed well from 2,030psi to 1,200psi fluid rose 11ft. POOH
and Perforate Beluga M1 (6345-6365) good pressure response from 1,571psi to 1,932psi in 5min. RD and move to A-18
Activity Report
Repair N2 pump, evacuate IA and tubing to 3,229’ with N2. RIH and reverse fluid out of the liner until dry. All wellbore fluid recovered.
Pop off well change out stripping rubber. Crane is down for maintenance.
RD Coil, RU E-line, Pressure test lubricator to 250psi/3500psi - Test Good. Secure well and SDNF
R/D from A-17, crew change, R/U on A-12B. Test BOPEs to 250psi/3500psi – Test good, witness waived by AOGCC, Jim Regg via email on
11/29/23 @ 0904hrs. MU YJ Motor and 3.75”od bit. Secure coil and SDFN.
PLAN FORWARD: Swap out drilling mud, pull CBL, N2 liŌ the IA.
RIH with motor and 3.75"OD bit dry tag at 6,935', wash to 7,391'. Pump 10bbl high vis sweep and circulate out drilling mud. Bring on N2
until IA was vacated. RIH w/ coil and CBL log from 7,380' to 3,000ft. Secure well, CBL data checks good.
Perforate Beluga S2 (6958-6978), Q4 (6719-6733), Q3 (6692-6715), and O1 (6449-6459). SITP slowly rising at 1psi/min throughout the
day.
Page 1 of 1
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%" A %" A
A
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.11.15 11:28:52 -09'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.11.15 14:19:36 -09'00'
Page 1/1
Well Name: NCIU A-12B
Report Printed: 1/2/2024
www.peloton.com
Casing
Intermediate2
Wellbore
Wellbore Name:
NCIU A-12B Total Depth of Wellbore (ftKB):
4,819.00 Original KB/RT Elevation (ft):
0.00
RKB to GL (ft):
0.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Intermediate2 Run Date:
11/4/2023 Set Depth (ftKB):
3,493.70
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf):
210,000.0 Block Weight (1000lbf):
55,000.0
Make-Up Contractor:
23820.0 Number Hrs to Run (hr):
22.00 Ft/Min (ft/min):
2.65
Run Job: Set Depth (ftKB):
3,493.70 Set Depth (TVD) (ftKB):
3,428.9
Centralizer Detail:
1 on every jt up to 1500'
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Casing Hanger 11 3/4 8.68 1.59 68.38 66.79
1 Casing Pup Joint 9 5/8 8.68 47.00 L-80 TXP-BTC 4.13 72.51 68.38
83 Casing Joints 9 5/8 8.68 47.00 L-80 TXP-BTC 3,336.60 3,409.11 72.51
1 Float Collar 10 3/4 8.68 1.36 3,410.47 3,409.11
2 Casing Joints 9 5/8 8.68 47.00 L-80 TXP-BTC 81.44 3,491.91 3,410.47
1 Float Shoe 10 3/4 8.68 1.79 3,493.70 3,491.91
Page 1/1
Well Name: NCIU A-12B
Report Printed: 1/2/2024
www.peloton.com
Cement
Intermediate Casing Cement
Type
Casing
Description
Intermediate Casing Cement
Cemented String
Intermediate2, 3,493.70ftKB
Wellbore
NCIU A-12B
Job
231-00109 NCIU A-12B Drilling, Drilling
- Drilling, 10/28/2023 06:00
Cementing Start Date
11/5/2023
Cementing End Date
11/5/2023
Top Depth (ftKB)
1,500.0
Cement Stages
Stage Number: <Stage Number?>
Description
Intermediate Casing Cement
Top Depth (ftKB)
1,500.0
Bottom Depth (ftKB)
3,500.0
Top Measurement Method
Volume Calculations
Pump Start Date
11/5/2023
Cement in Place At
11/5/2023
Final Circulating Pressure (psi)
866.0
Plug Bump Pressure (psi)
1,350.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
0.0
Volume Lost (bbl)
8.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer)10.50 60.0 60.0 4
Lead Slurry G 220 2.44 12.00 94.0 94.0 4
Tail Slurry G 236 1.16 15.80 48.0 48.0 4
Displacement 9.10 249.0 249.0 3 Mud Pump 2
Post Job Calculations
Subtype Value
Page 1/1
Well Name: NCIU A-12B
Report Printed: 1/2/2024
www.peloton.com
Casing
Prodbction1
WellTore
WellTore Name:
NCIU A-12B Dotal heptf o( WellTore K(t) BO:4,819.00 Eriginal ) B/RDvleGation K(tO:0.00
R) B to LF K(tO:0.00 ) B-Casing ulange histance K(tO: ) B-DbTing Hanger histance K(tO:
PBDhs
heptf K(t) BO:
Casing
Casing hescription:
Production1 Rbn hate:
11/15/2023 Set heptf K(t) BO:7,517.00
Casing Weigf t on Slips K1000lT(O:PickUpWeigftK1000lT(O: Block Weigf t K1000lT(O:
Make-Up Contractor:
23820.0 NbmTer Hrs to Rbn KfrO:ut/MinK(t/minO:
Rbn JoT:
231-00109 NCIU A-12B Drilling, Drilling -
Drilling, 10/28/2023 06:00
Set heptf K(t) BO:7,517.00 Set heptf KDVh OK(t) BO:6,964.5
Centralizer hetail:
every JT
AttriTbte SbTtype: Valbe:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No uloat uailed?:
No
Dest SbTtype: Pressbre KpsiO:
Casing KEr FinerOhetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Float Shoe 5 1/4 1.63 TXP-BTC 1.45 3,301.48 3,300.03
Blank Liner 4 1/2 3.96 12.60 TXP-BTC 39.65 3,341.13 3,301.48
Float Collar 5 1/4 1.88 TXP-BTC 1.38 3,342.51 3,341.13
Blank Liner 4 1/2 3.96 12.60 TXP-BTC 39.63 3,382.14 3,342.51
Collar 5.04 2.40 TXP-BTC 1.07 3,383.21 3,382.14
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 39.70 3,422.91 3,383.21
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 41.22 3,464.13 3,422.91
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 794.04 4,258.17 3,464.13
RA tag collar 4 1/2 3.96 12.60 L-80 TXP-BTC 39.71 4,297.88 4,258.17
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 119.67 4,417.55 4,297.88
Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 8.24 4,425.79 4,417.55
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 833.14 5,258.93 4,425.79
RA tag collar 4 1/2 3.96 12.60 L-80 TXP-BTC 41.33 5,300.26 5,258.93
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 159.26 5,459.52 5,300.26
Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 8.31 5,467.83 5,459.52
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 1,032.18 6,500.01 5,467.83
Casing Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 8.34 6,508.35 6,500.01
Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 957.17 7,465.52 6,508.35
Seal bore Extension 7.62 4.00 hyd 563 BAKER OIL
TOOLS
29.88 7,495.40 7,465.52
SLZXP liner top Hanger packer 8.42 7.38 BAKER OIL
TOOLS
21.60 7,517.00 7,495.40
Page 1/1
Well Name: NCIU A-12B
Report Printed: 1/2/2024
www.peloton.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Production1, 7,517.00ftKB
Wellbore
NCIU A-12B
Job
231-00109 NCIU A-12B Drilling, Drilling
- Drilling, 10/28/2023 06:00
Cementing Start Date
11/16/2023
Cementing End Date
11/16/2023
Top Depth (ftKB)
Cement Stages
Stage Number: 1
Description
Liner Cement
Top Depth (ftKB) Bottom Depth (ftKB) Top Measurement Method
Volume Calculations
Pump Start Date
11/16/2023
Cement in Place At
11/16/2023
Final Circulating Pressure (psi)
900.0
Plug Bump Pressure (psi)
1,550.0
Full Return?
Yes
Returns During Job (%)
99
Volume to Surface (bbl)
40.0
Volume Lost (bbl)
4.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer)8.40 10.0 10.0 2 HES
CEMENT
PUMP
Preflush (Spacer)11.00 30.0 30.0 4 HES
CEMENT
PUMP
Lead Slurry 620 12.00 260.0 260.0 5 HES
CEMENT
PUMP
Tail Slurry 181 15.30 37.0 37.0 3 HES
CEMENT
PUMP
Displacement 8.40 10.0 10.0 5 HES
CEMENT
PUMP
Displacement 10.30 93.0 93.0 5 RIG PUMP
Post Job Calculations
Subtype Value
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 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-12B 50883200320200 223053 12/1/2023 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:Karson Kozub; Dan Marlowe; Juanita Lovett
Subject:RE: NCIU A-12B CBL (PTD #223-053)
Date:Tuesday, December 5, 2023 12:13:00 PM
Ryan,
Hilcorp has approval to proceed with perforating per sundry 323-626.
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: Monday, December 4, 2023 12:18 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Karson Kozub <kkozub@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett
<jlovett@hilcorp.com>
Subject: NCIU A-12B CBL (PTD #223-053)
Bryan-
Here’s the CBL for NCIU A-12B. Please let us know if we have approval to perforate per attached
sundry. Thanks,
Ryan Rupert
CIO Ops Engineer (#13088)
907-301-1736 (Cell)
907-777-8503 (Office)
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: 12/01/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-12B
PTD: 223-053
API: 50-883-20032-02-00
FINAL LWD FORMATION EVALUATION LOGS (10/13/2023 to 11/10/2023)
x ROP, EWR-P4, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer – Data Main Folders:
Please include current contact information if different from above.
PTD:223-053
T38196
12/4/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.04
10:36:40 -09'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,519 N/A
Casing Collapse
Structural
Conductor
Surface 2,670psi
Intermediate 4,760psi
Production
Liner 7,500psi
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Ryan Rupert
Contact Email:Ryan.Rupert@hilcorp.com
Contact Phone:(907) 777-8503
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Other: CT Operations / N2
11/24/2023
7,517'4,217'
4-1/2"
6,965'
LTP & TRSSSV 3,300 (MD) 3,267 (TVD) & 465 (MD) 465 (TVD)
Perforation Depth MD (ft):
3,494'
±4,745 -±7,434 (proposed)
4-1/2"
±4,457 -±6,885 (proposed)
381' 30"
20"
13-3/8"
1,990'
9-5/8"3,494'
2,640'
MD
6,870psi
5,380psi
1,990'
2,640'
3,429'
1,990'
2,640'
Length Size
Proposed Pools:
381' 381'
L-80
TVD Burst
±3,332 (proposed)
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589 / ADL0037831
223-053
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20032-02-00
Hilcorp Alaska, LLC
CO 68A
AOGCC USE ONLY
8,430psi
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-12B
N Cook Inlet N/A Tertiary System Gas
6,966 7,434 6,885 2,892psi 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 7:48 am, Nov 20, 2023
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2023.11.17 17:31:34 -
09'00'
Dan Marlowe
(1267)
323-626
Yes for CT work
BJM 11/27/23
CT BOP test to 3500 psi. Approval granted to test BOP's weekly for 3-well campaign with NCIU A-17
and NCIU A-18.
A.Dewhurst 22NOV23
X
DSR-11/20/23
11/21/23
Bryan McLellan
10-407
*&:JLC 11/27/2023
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.11.27 15:27:47 -09'00'11/27/23
RBDMS JSB 112823
Initial Completion
Well: NCIU A-12B
Well Name:NCIU A-12B API Number:50-883-20032-02-00
Current Status:New sidetrack gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:223-053
First Call Engineer:Ryan Rupert (907) 301-1736 (c)
Second Call Engineer:Dan Marlowe (907) 398-9904 (c)
Maximum Expected BHP:3,581 psi @ 6,885’ TVD 0.52psi/ft to deepest perf
Max. Potential Surface Pressure: 2892 psi Using 0.1 psi/ft
Brief Well Summary
Spartan 151 has successfully sidetracked Tyonek well A-12B as part of the 2023 drilling campaign. The jackup rig
will now be leaving 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:All are planned details, as the tubing is being installed 11/17/23
- TRSSSV to be installed
-Live GLV’s to be installed
- Fluids from 11/16/23
o Rig displaced 4-1/2” liner wiper plug with 10.3ppg mud
o Upper completion tubing and IA planned for FIW
- MIT’s
o MIT-IA and MIT-T planned
Initial Completion
Well: NCIU A-12B
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 = 286bbls
i. IA Volume to bottom GLV: 173bbls
ii. Tubing Volume: 50bbls
iii. Liner volume: 63 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 ±4,745’ - ±7,434’ MD (±4,457’ - ±6,885’ 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
Updated By: JLL 11/17/23
SCHEMATIC
North Cook Inlet Unit
Well: NCIU A-12B
PTD: 223-053
API: 50-883-20032-02-00
PBTD: 7,434’ TD: 7,519’
30”
RKB: MSL = 126.6’
3-4
2
9-5/8”
4-1/2”
13-3/8”
Window @
2,640’ MD
20”
1
X
Casing &Tubing Detail
Size Wt Grade Conn ID Top Btm
30” 133 H-40 Welded 28.000 Surf 381’
20” 133 H-40 19.730 Surf 1,990’
13-3/8” 72 N-80 BTC 12.347 Surf 2,640’
9-5/8” 47 L-80 TXP 8.681 Surf 3,494’
4-1/2” 12.6 L-80 TXP 3.985 3,300’ 7,517’
4-1/2” 12.6 L-80 Hyd 533 3.985 Surf ±3,332’
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 ±1,958’ ±1,958’ 3.937 Dome
2 ±3,229’ ±3,205’ 3.937 Orifice
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)
ID Item
1 ±465’ ±465’ 3.813 TRSSSV
2 ±3,284’ ±3,253’ 3.813 X Nipple 3.813” Profile
3 3,300’ 3,267’ 7.375 Liner hanger / LTP Assembly
4 3,332’ 3,294’ 3.870 Seal Stem
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Note:
5,517’ RA Marker
6,519’ RA Marker
Cement Details
9-5/8"12-1/4" Hole: Pumped 93 bbls of 12.0ppg lead cement followed by 48 bbls of 15.8ppg tail cement. 8 bbls lost
during job. Assuming 30% openhole washout,volumetric ToC = 1,550’ MD
4-1/2”8.5” hole: Pumped 260 bbls of 12.0ppg lead cement followed by 37 bbls of 15.3ppg tail cement. 40bbls cement
circulated back to surface from liner top.ToC = ToL.
Updated By: JLL 11/17/23
PROPOSED
North Cook Inlet Unit
Well: NCIU A-12B
PTD: 223-053
API: 50-883-20032-02-00
PBTD: 7,434’ TD: 7,519’
30”
RKB: MSL = 126.6’
3-4
2
9-5/8”
4-1/2”
13-3/8”
Window @
2,640’ MD
20”
1
X
Casing &Tubing Detail
Size Wt Grade Conn ID Top Btm
30” 133 H-40 Welded 28.000 Surf 381’
20” 133 H-40 19.730 Surf 1,990’
13-3/8” 72 N-80 BTC 12.347 Surf 2,640’
9-5/8” 47 L-80 TXP 8.681 Surf 3,494’
4-1/2” 12.6 L-80 TXP 3.985 3,300’ 7,517’
4-1/2” 12.6 L-80 Hyd 533 3.985 Surf ±3,332’
GAS LIFT MANDRELS
STA MD TVD ID Type Port Valve Psc Date
1 ±1,958’ ±1,958’ 3.937 Dome
2 ±3,229’ ±3,205’ 3.937 Orifice
JEWELRY DETAIL
No.Depth
(MD)
Depth
TVD)
ID Item
1 ±465’ ±465’ 3.813 TRSSSV
2 ±3,284’ ±3,253’ 3.813 X Nipple 3.813” Profile
3 3,300’ 3,267’ 7.375 Liner hanger / LTP Assembly
4 3,332’ 3,294’ 3.870 Seal Stem
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
BEL ±4,745’ ±7,434’ ±4,457’ ±6,885’ ±2,689’ Future Proposed
Note:
5,517’ RA Marker
6,519’ RA Marker
Cement Details
9-5/8"12-1/4" Hole: Pumped 93 bbls of 12.0ppg lead cement followed by 48 bbls of 15.8ppg tail cement. 8 bbls lost
during job. Assuming 30% openhole washout,volumetric ToC = 1,550’ MD
4-1/2”8.5” hole: Pumped 260 bbls of 12.0ppg lead cement followed by 37 bbls of 15.3ppg tail cement. 40bbls cement
circulated back to surface from liner top.ToC = ToL.
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
the content is safe.
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.
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: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.
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-12BPTD 2230530
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:Sean McLaughlin
Subject:RE: Live GLMs in the tie-back on Tyonek A-17 and A-12B wells
Date:Friday, October 6, 2023 3:57:00 PM
Sean,
Hilcorp has approval to make the proposed changes to the approved PTD’s for A-17 (PTD 223-031)
and A-12B (PTD 223-053).
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, October 6, 2023 2:12 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Live GLMs in the tie-back on Tyonek A-17 and A-12B wells
Bryan,
The tie-back plan on Tyonek wells A-17 and A-12B has changed to include running live GLMs instead
of GLMs with dummy valves. Instead of a tubing and IA test, a CMIT will be performed followed by a
MIT-T. I view this as a minor change but wanted to ensure no agency approval is required.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
STATE OF ALASKA
Reviewed By:
OIL AND GAS CONSERVATION COMMISSION P.I. Supry JBR 01/12/2024
BOPE Test Report for: N COOK INLET UNIT A-12B Comm
Rig Owner/Rig No.: Enterprise 151�
PTR 2230530 DATE:
11/12/2023 Inspector Guy Cook
Insp Source
Operator: Hilcorp Alaska, LLC
Operator Rep: S. Hauck/L. Moore
Rig Rep: A. Boy( Herbert
Inspector
Type Operation: DRILL
Sundry No:
Test Pressures:
Inspection No: bopGDC231111170710
,i
Rama: Annular: Valves:
MASP:
Type Test: BIWKLY
Related Insp No:
250/3000 250/3000 250/3000
2926
TEST DATA
MISC. INSPECTIONS:
MUD SYSTEM:
ACCUMULATOR SYSTEM:
P/F
Visual Alarm
Time/Pressure P/F
Housekeeping: P
Trip Tank P P
System Pressure 3100 P
PTD On Location P
Pit Level Indicators P P
Pressure After Closure 1900 P
Standing Order Posted P
Flow Indicator P P
200 PSI Attained 18 P
Well Sign P
Meth Gas Detector
Full Pressure Attained 136 P
Hazard Sec. P
112S Gas Detector P P
Blind Switch Covers: All Stations P
Test Fluid W
MS Misc NA NA
Bottle precharge P
Misc NA
Nitgn Btls# &psi (avg) 1662100 P
ACC Misc 0 NA
FLOOR SAFTY VALVES:
BOP STACK:
CHOKE MANIFOLD:
Quantity P/F
Quantity Size P/F
Quantity P/F
Upper Kelly 1 P
Stripper 0
NA
No. Valves 13 P
Lower Kelly 1 P
Annular Preventer 1 13 5/811 5000
P
Manual Chokes 1 P
Ball Type 2 P
#1 Rams 1 4.511x71 VBR
P
Hydraulic Chokes 2 P
Inside BOP 1 P
#2 Rams 1 Blind/Shear
P
CH Misc 0 NA
FSV Misc 0 NA
#3 Rams 1 4.511x711 VBR
P
Control System Response Time (sec)
Time P/F
#4 Rams 0
#5 Rams 0
NA
NA
INSIDE REEL VALVES:
#6 Rams 0
NA
Annular Preventer 14 P
(Valid for Coil Rigs Only)
Choke Ln. Valves 1 3 1/811 5000
P
#1 Rams 14 P
Quantity P/F
Inside Reel Valves 0 NA
HCR Valves 2 3 1/811 5000
P
#2 Rams 14 P
Kill Line Valves 3 3 1/811 5000
P
#3 Rams 13 P
Check Valve 0
NA
#4 Rams 0 NA
BOP Misc 0
NA
#5 Rams 0 NA
#6 Rams 0 NA
HCR Choke 2 P
HCR Kill 2 P
Number of Failures: 1 °
Test Results
Test Time 8
Remarks: 4.5 test joint used for
testing. The shaker LEL failed to go off on the audible
alarm. The detector was recalibrated and retested
good.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet Unit Field, Tertiary System Gas Pool, NCIU A-12B
Hilcorp Alaska, LLC
Permit to Drill Number: 223-053
Surface Location: 1254' FNL, 928' FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 427' FNL, 910' FEL, Sec 1, 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 August 2023. 7
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.08.07
20:26:57 -08'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 7,504' TVD: 6,966'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 126.6' 15. Distance to Nearest Well Open
Surface: x- 331994 y- 2586723 Zone-4 N/A to Same Pool: 1358' to NCIU A-13
16. Deviated wells:Kickoff depth: 2,630 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 36 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
12-1/4" 9-5/8" 47# L-80 TXP 3,470' Surface Surface 3,470' 3,420'
6-3/4" 4-1/2" 12.6# L-80 TXP 4,234' 3,270' 3,249' 7,504' 6,966'
Tieback 4-1/2" 12.6# L-80 IBT 3,270' Surface Surface 3,270' 3,249'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
381'
1990'
6,950'
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
NCIU A-12B
North Cook Inlet Unit
Tertiary System Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
N/A
1820 sx13-3/8"
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Tieback Assy.
2926
1225' FNL, 873' FWL, Sec 6, T11N, R9W, SM, AK
427' FNL, 910' FEL, Sec 1, T11N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1254' FNL, 928' FWL, Sec 6, T11N, R9W, SM, AK ADL17589 / ADL37831
18. Casing Program:Top - Setting Depth - BottomSpecifications
3622
GL / BF Elevation above MSL (ft):
Cement Volume MDSize
Plugs (measured):
(including stage data)
L - 517 ft3 T - 255 ft3
L - 743 ft3 / T - 104 ft3
2,665'2,665'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
7,352'6,911'
LengthCasing
2,665'
N/A
Conductor/Structural 30"381'
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
6,950'Intermediate
Driven 381'
1,990'20"1142 sx
Drilling Manager
Monty Myers
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
1,990'
6,950'
8/1/2023
5340' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
8328
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
s
D
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
6.14.2023
By Grace Christianson at 9:35 am, Jun 14, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.06.14 06:58:49 -08'00'
Monty M
Myers
ADD 26JUL2023
BOP test to 3000 psi. Annular test to 2500 psi.
DSR-6/15/23
223-053 50-883-20032-02-00
BJM 7/28/23
Submit FIT/LOT results to AOGCC within 48 hrs of performing tests.
GCW 08/07/2023JLC 8/7/2023
08/07/23
08/07/23
Brett W. Huber, Sr.Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.07 20:27:17 -08'00'
A-12B Drilling Program
Tyonek
Sean McLaughlin
PTD
June 12, 2023
NCI A-12B
Drilling Program
PTD
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. R/U and Preparatory Work.........................................................................................................11
11. BOP N/U and Test.......................................................................................................................11
12. Set Whipstock / Mill Window......................................................................................................12
13. Drill 12-1/4” Intermediate Hole Section ......................................................................................13
14. Run 9-5/8” Intermediate Casing .................................................................................................15
15. Cement 9-5/8” Surface Casing ....................................................................................................17
16. Production hole Preparatory Work and Mud Program.............................................................20
17. Drill 6-3/4” Hole Section ..............................................................................................................21
18. Run 4-1/2” Production Liner.......................................................................................................23
19. Cement 4-1/2” Production Liner .................................................................................................26
20. Wellbore Clean Up & Displacement...........................................................................................28
21. Run Completion Assembly..........................................................................................................28
22. BOP Schematic............................................................................................................................30
23. Proposed Wellhead Schematic....................................................................................................31
24. Anticipated Drilling Hazards......................................................................................................32
25. Jack up position...........................................................................................................................33
26. FIT Procedure..............................................................................................................................34
27. Choke Manifold Schematic .........................................................................................................35
28. Casing Design Information..........................................................................................................37
29. 12-1/4” Hole Section MASP.........................................................................................................38
30. 6-3/4” Hole Section MASP...........................................................................................................39
31. Plot (NAD 27) (Governmental Sections).....................................................................................40
32. Slot Diagram................................................................................................................................41
33. Directional Program (wp02) - Attached separately...................................................................42
Page 2 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
1. Well Summary
Well NCI A-12B
Drilling Rig Rig 151
Leg & Slot Leg 1 / Slot 3
Directional plan wp02
Pad & Old Well Designation Sidetrack from A-12A
Planned Completion Type 4-1/2”12.6# Liner, 4-1/2” Tubing GL Comp
Target Reservoir(s)Beluga A-U
Kick off point 2630’
Planned Well TD, MD / TVD 7504’MD / 6966’TVD
PBTD, MD 7404’MD
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’
Page 3 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
2. Management of Change Information
Date: June 12, 2023
Subject: Changes to Approved Permit to Drill
File #: NCI A-12B Drilling Program
Significant modifications to Drilling Program for PTD will be documented and approved below. Changes to an
approved PTD will be communicated and approved by the AOGCC prior to continuing forward with work.
Sec Page Date Procedure Change Approved By
Approval:
Drilling Manager Date
Prepared:
Engineer Date
Page 4 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
3. Tubular Program
Hole Section OD (in)ID (in)Drift (in)Conn
OD (in)
Wt
(#/ft)Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
12-1/4”9.625”8.681”8.525”10.625”47 L-80 TXP 6870 4750 1086
6-3/4”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)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 16,176 10,959 468k
Page 5 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
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. Garrett St. Clair: C: (907) 252-7780
x Spills:
i. Keegan Fleming: C:907-350-9439
ii. Monty Myers: O: 907-777-8431 C: 907-538-1168
iii. Sean Mclaughlin
x Submit Hilcorp Incident report to contacts above within 24 hrs
4. Casing Tally
x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com
5. Casing and Cmt report
x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and
cdinger@hilcorp.com
Page 6 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
6. Current Wellbore Schematic
Page 7 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
7. Planned Wellbore Schematic
Page 8 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
8. Drilling Summary
A-12B is a 7504’ MD / 6966’ TVD development gas well drilled from leg 1 slot #3 off the Tyonek platform.
The plan is an infill wellbore to the Beluga U.
The well will be completed with a 4-1/2”gas lift tie-back completion.
Drilling operations are expected to commence approximately August 2023.
General sequence of operations pertaining to this drilling operation:
Rig
1. Rig 151 will MIRU over leg 1, slot 3
2. N/U and test 13-5/8” x 5M BOP to 3000 psi
3.Run whipstock and mill 20’ of new formation
4. Perform FIT to 12.0 ppg EMW
5. PU 8” motor drilling assembly and TIH to window.
x Eline Gyro required due to vertical wellbore
6. Drill 12-1/4” intermediate hole to 3470’MD, performing short trips as needed
x GR only
7. RIH w/ 9-5/8” casing to surface and cement to 1500’.
8. Perform casing test to 3500 psi. Swap rams to 4-1/2”.
9. PU 4-3/4”motor drilling assembly and TIH to window.
10.Mill shoe track and 20’ of new hole.
11. Perform FIT to 14.8 ppg EMW
12. Drill 6-3/4” production hole to 7504’MD, performing short trips as needed
x Triple Combo, GeoTap (RFT)
13. RIH w/ 4-1/2” liner. Set liner and cement. Circ wellbore clean.
14. Perform Clean out run to polish bore
15. Perform liner lap test to 2000 psi.
16. Run 4-1/2”gas lift completion.
17. Land hanger and test T&IA to 3000 psi.
18. ND BOPE, NU tree and test void
Page 9 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
9. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
o The MASP for the intermediate hole is 1148 psi.
o The highest reservoir pressure expected is 3622 psi in the Beluga U sand (6966' TVD). MASP is
2926 psi with 0.1psi/ft gas in the wellbore.
x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi. The top
casing spool has a 3M rating.
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 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4 and 6-3/4”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 10M Cameron U Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 10M Cameron U single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 11 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
10. R/U and Preparatory Work
1. Mix WBM mud for 12-1/4” hole section.
2. Install 7” liners in mud pumps. Plan to pump at 1000 gpm to clean the 30”conductor. 7” liners will
deliver 575 gpm @ 98% eff @ 3623 psi.
11. BOP N/U and Test
1. N/D Tree and adapter. Install test plug
2. N/U to 13-5/8” 5M Multi bowl spool (3M bottom flange)
3. N/U 13-5/8” x 5M BOP as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” 10M Cameron U Double ram. (9-5/8” rams in top cavity, blind ram in btm cavity)
x 13-5/8” mud cross
x 13-5/8” 10M Cameron U single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master
valve”.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
x 13-5/8” 5M x 13-5/8 10M adapter required.
4. Test BOPE.
x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
Page 12 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug. Confirm the correct valves are opened!!!
x Test VBRs on a 4.5” test joint (3000 psi)
x Test Annular on 4.5” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
5. Pull test plug
12. Set Whipstock / Mill Window
Operation Steps:
1. Make up the 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. Circulate the hole to clean 9.0 ppg. Perform 2000 psi 13-3/8” casing test.
4. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg ROHS.
x A drop gyro will be required for orienting the WS (INC at set depth is 1.75 deg).
5. Set the top of the whipstock at ~2630’ MD
x 13-3/8” Collars at 2621’ and 2662’
x Ref log: AK eline Collar log 7-SEP-22
6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
Page 13 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
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.
7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 12.0 ppg.
¾Assuming the kick zone is at 3470’, a FIT of 12.0 ppg EMW gives an Unlimited Kick Tolerance volume
with 9.0 ppg mud weight.
¾The OA is cemented up to 1950’ (top of 1997 CBL). Monitor OA during FIT and report and change in
pressure.
8. 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.
9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
13. Drill 12-1/4” Intermediate Hole Section
1. Ensure BHA components have been inspected previously.
2. Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
3. TIH, conduct shallow hole test of MWD and confirm LWD tools functioning properly.
4. Ensure TF offset is measured accurately and entered correctly into the MWD software.
5. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
6. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to
pick up pipe from the pipeshed.
7. 12-1/4” hole section mud program summary:
Page 14 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
Weighting material to be used for the hole section will be salt and calcium carbonate. Additional
calcium carbonate will be on location to weight up the active system (1) ppg above highest
anticipated MW.
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, Toolpusher office, and mud
loggers office.
System Type: LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
2630’-
3470’
8.8-9.8 40-53 6-15 13-24 8.5-9.5 11.0
System Formulation: 2% KCL/BDF-976/GEM GP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
DEXTRID LT
PAC L
BDF-976
GEM GP
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROTROL PLUS
SOLTEX
BAROID 41
ALDACIDE-G
0.905 bbl
7 ppb
0.2 ppb (9 pH)
1.0 ppb (as required 18 YP)
1-2 ppb
1 ppb
4 ppb
1.0% by volume
5 ppb (1.7 ppb of each)
5 ppb (1.7 ppb of each)
1.7 ppb
4.0 ppb
2 –4 ppb
as needed
0.1 ppb
8. TIH w/ 12-1/4” directional assy to top of window. Shallow test MWD and LWD on trip in.
9. Drill 12-1/4” hole section to 3470’ MD / 3424’ TVD
x GR only for intermediate hole
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at ~1000 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled at a minimum. Surveys can be taken more frequently
if deemed necessary.
Page 15 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
10. At TD, pump sweeps, CBU, and pull a wiper trip back to the window.
11. Once back on bottom after wiper trip, CBU to condition hole for casing run.
12. POOH and LD BHA
14. Run 9-5/8” Intermediate Casing
1. R/U and pull wear bushing.
2. R/U Parker (Volant) 9-5/8” casing running equipment.
x Ensure 9-5/8” TXP x CDS40 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Plan to rig up Volant CRT if available
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
3. P/U shoe joint, visually verify no debris inside joint.
4. Continue M/U & thread locking 90’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint –9-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring
9-5/8” Float Collar
1 joint –9-5/8” BTC, 1 Free floating centralizer
9-5/8” Landing collar
5. Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to 1500’ MD (Planned TOC)
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns.
Page 16 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
Page 17 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
6. Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization: No centralizers in the conductor.
7. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary.
8. Slow in and out of slips.
9. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it
is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger.
10. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed
out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed.
11. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while
circulating.
12. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected.
However, in the event cement is circulated out ensure hose is in place to take returns and dump into the
inlet over the side of the platform.
15. Cement 9-5/8” Surface Casing
1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well. Ensure
mud & water can be delivered to the cementing unit at acceptable rates.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
2. Document efficiency of all possible displacement pumps prior to cement job.
Page 18 PTD June 12, 2023
NCI A-12B
Drilling Program
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3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help
ensure any debris left in the cement pump or treating iron will not be pumped downhole.
4. R/U cement line (if not already done so).
5. Fill surface cement lines with water and pressure test.
6. Pump remaining 60 bbls 10.5 ppg tuned spacer.
7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD
is reached.
8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC
brought to 1500’.
Estimated Cement Volume:
Cement Slurry Design:
9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation
PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with
the cement job.
10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
13-3/8" Casing x 9-5/8" Liner (2630-1500) x 0.0581 bpf 65.7 368.3
12-1/4" OH x 9-5/8" Liner (2970-2630) x 0.0558 bpf x 1.4 26.6 149.0
Total Lead 92.2 517.3 220.1
12-1/4" OH x 9-5/8" Liner (3470-2970) x 0.0558 bpf x 1.4 39.0 219.1
9-5/8" Shoetrack 90' x 0.0706 bpf 6.4 35.6
Total Tail 45.4 254.7 219.6
TOTAL CEMENT VOLUME 138 772 440
Casing Displacement 239
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
Page 19 PTD June 12, 2023
NCI A-12B
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x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
11. Ensure rig pump is used to displace cement.
12. Land hanger.
13. Displacement volume is in Table above.
14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point
during the job.
15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by
no more than 1 shoe track volume, ±6 bbls before consulting with Drilling Engineer.
16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are
holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is
set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if
pressure must be held, this is to ensure the stage tool is not prematurely opened.
17. Not expected, but be prepared for cement returns to surface. Cement return to be taken overboard.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with
the cement.
18. R/D cement equipment. Flush out wellhead with FW.
19. Back out and L/D landing joint. Flush out wellhead with FW.
20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in
lock downs and inject plastic packing element.
21. Lay down landing joint and pack-off running tool.
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 casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
Page 20 PTD June 12, 2023
NCI A-12B
Drilling Program
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x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and
cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC.
16. Production hole Preparatory Work and Mud Program
1. Swap 9-5/8” casing rams to 2-7/8” X 5” VBR’s. Test to 3000 psi
2. Test 9-5/8” casing to 3500 psi. 30 minute charted.
3. Mix 9.0 WBM mud for 6-3/4” hole section.
4. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s)
x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm
at 115 spm.
x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps.
5. 6-3/4” 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
Page 21 PTD June 12, 2023
NCI A-12B
Drilling Program
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Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
3470’-TD 8.8-10.4 40-53 6-15 13-24 8.5-9.5 11.0
**Ensure MW of 10.0 ppg prior to drilling into the Beluga I (5836’ MD /5376’ TVD)**
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
0.2 ppb
6. 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.
7. 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.
17. Drill 6-3/4” Hole Section
1.M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22°PDM)
2. TIH w/ 8-1/2” cleanout BHA to Landing Collar.
3.Drill out shoe track and 20’ of new formation.
4. CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean
up debris.
Page 22 PTD June 12, 2023
NCI A-12B
Drilling Program
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5. Conduct FIT to 14.8 ppg EMW. Chart test. Document incremental volume pumped (and subsequent
pressure) and volume returned.
x A 14.0 ppg FIT with 10 ppg BHP and 10.1ppg mud equates to a 26 bbl KTV
6. POOH & LD Cleanout BHA
7. Drift & caliper all MWD components before M/U. Visually verify no debris inside components that
cannot be drifted.
8. Ensure TF offset is measured accurately and entered correctly into the MWD software.
9. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at 150 - 300 gpm.
10. P/U 4-3/4” Sperry Sun motor drilling assy w/ triple combo (DEN, POR, RES) and GeoTap RFT.
11. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and
drop sections of the wellbore.
12. Primary bit will be the Baker Hughes Kymera 6-3/4” K5M323. Ensure to have a backup PDC bit
available on location.
13. TIH to window. Shallow test MWD on trip in.
14. Drill 6-3/4” hole to 7504’ MD using motor assembly.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be
provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal
seams once drilled.
x Keep swab and surge pressures low when tripping.
x 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
x Ensure MW of 10.0 ppg prior to drilling into the Beluga I (5836’ MD /5376’ TVD)
15. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement
calculations. CBU, and pull a wiper trip back to the window.
16. Perform repeat formation pressure testing per geologist (number of test stations TBD).
Page 23 PTD June 12, 2023
NCI A-12B
Drilling Program
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17. TOH with drilling assembly, handle BHA as appropriate.
18. 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
x Centralizers will be run on 4-1/2” liner every joint.
x Ensure proper operation of float shoe & FC.
4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’, RA Tag 1000’ and 2000’ from bottom.
x Fill liner while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
Page 24 PTD June 12, 2023
NCI A-12B
Drilling Program
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5.Ensure to run enough liner to provide at least 100’ overlap inside casing . Ensure setting sleeve will
not be set in a connection.
Page 25 PTD June 12, 2023
NCI A-12B
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6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make
sure it coincides with the pipe tally.
7.M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin
enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up.
8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner.
9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
10. M/U top drive and fill pipe while lowering string every 10 stands.
11. Set slowly in and pull slowly out of slips.
12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” shoe prior to going into open hole. Stage pumps up
slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15.P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
Page 26 PTD June 12, 2023
NCI A-12B
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19. 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 3270’ 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 10.0 ppg WBM.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
9-5/8" Casing x 4-1/2" Liner (3470-3270) x 0.0535 bpf 10.7 60.1
6.75" OH x 4-1/2" Liner (7004-3470) x 0.0246 bpf x 1.4 121.7 682.5
Total Lead 132.4 742.6 316.0
6.75" OH x 4-1/2" Liner (7504-7004) x 0.0246 bpf x 1.4 = 17.2 96.6
4-1/2" Shoetrack 90' x 0.0152 bpf = 1.4 7.7
Total Tail 18.6 104.2 89.9
TOTAL CEMENT VOLUME 151 847 90
Displacement DP+ Liner 110
Le
a
d
Ta
i
l
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
Page 27 PTD June 12, 2023
NCI A-12B
Drilling Program
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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 28 PTD June 12, 2023
NCI A-12B
Drilling Program
PTD
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
20. 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.
21. Run Completion Assembly
1. Run 4-1/2” tubing completion assembly to above the liner top
x Tubing will be 4-1/2” L-80 12.6# IBT
x SSSV to be placed at 500’
x CIM to be placed at 2000’
x GLM will be run.
2. Swap the well over to FIW
Page 29 PTD June 12, 2023
NCI A-12B
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x Circulate a hi-vis pill followed by a soap train per Baroid
x Circulate FIW until clean-up is satisfactory.
x Leave FIW in the annulus.
3. Space out and land seal bore in tie back sleeve. RILDs.
4. Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min test
5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
Page 30 PTD June 12, 2023
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22. BOP Schematic
Page 31 PTD June 12, 2023
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23. Proposed Wellhead Schematic
Casing spool, OCT- TC,
21 ¼ 2M x 13 5/8 3M,
w/ 2- 2 1/16 5M EFO
Starting head, OCT-C22,
21 1/4 2M x 20'’ SOW,
w/ 2- 2'’ LPO
20'’
13 3/8'’
Multi-bowl, Cactus MBS-2,
13 5/8 5M top x 13 5/8 3M
bottom
w/ 2- 2 1/16 5M SSO
Wellhead does not have slips
as drawn it is a mandrel
hanger from the 70's
Unknown neck size
Existing on well
Equipment needed
7 5/8'’ or 7'’
4 ½’’
Valve, Master, WKM-M,
4 1/16 5M FE, HWO,
EE trim
Valve, Upper master,
WKM-M,
4 1/16 5M FE, HWO, EE trim
Valve, Swab, WKM-M
4 1/16 5M FE, HWO,
EE trim
BHTA, Otis, 4 1/16 5M FE x
9.5 Otis quick union top
Valve, Wing, SSV, WKM-M,
3 1/8 5M FE, w/ 15'’ air operator
Adapter, Cactus-EN-6.25'’,
13 5/8 5M stdd x 4 1/16 5M
stdd top, w/ 2- 1'’npt control
line exits
Tubing hanger, Cactus-EN-
CCL, 13 x 4 ½ EUE 8rd lift and
susp x w 6 ¼ od ext neck, 4'’
type H BPV profile, DD-NL
material
Tyonek Platform
A-12
20 x 13 3/8 x 7 5/8 or 7 x 4 ½
9-5/8”
Page 32 PTD June 12, 2023
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24. Anticipated Drilling Hazards
Lost Circulation:
Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and
A-01A)
x Maintain sufficient volumes while drill.
x Maintain ability to take on FIW during drilling phase
x If a LC event occurs pumping cement will be the likely remedy
Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition
carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize
solids control equipment to maintain density and minimize sand content. Maintain programmed mud
specs.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
x Minimize swab and surge pressures
x Minimize back reaming through coals when possible
H2S:
H2S is not present in this hole section.
Anti Collision: NONE
Pressure Ramp:Ensure mud weight is at least 10.0 ppg prior to drilling into the Beluga I
Page 33 PTD June 12, 2023
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25. Jack up position
Page 34 PTD June 12, 2023
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26. 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 35 PTD June 12, 2023
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27. Choke Manifold Schematic
Page 36 PTD June 12, 2023
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Drilling Program
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Page 37 PTD June 12, 2023
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28. Casing Design Information
Page 38 PTD June 12, 2023
NCI A-12B
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29. 12-1/4” Hole Section MASP
Page 39 PTD June 12, 2023
NCI A-12B
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30. 6-3/4” Hole Section MASP
Page 40 PTD June 12, 2023
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31. Plot (NAD 27) (Governmental Sections)
Page 41 PTD June 12, 2023
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32. Slot Diagram
Page 42 PTD June 12, 2023
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33. Directional Program (wp02) - Attached separately.
!""
# !
# ! $
$
2100
2450
2800
3150
3500
3850
4200
4550
4900
5250
5600
5950
6300
6650
7000
7350
Tr
u
e
V
e
r
t
i
c
a
l
D
e
p
t
h
(
7
0
0
u
s
f
t
/
i
n
)
-350 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550
Vertical Section at 294.00° (700 usft/in)
NCI A-12B wp01 tgt1
NCI A-12B wp01 tgt3
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500
A-12
2000
2500
3000
3500
4 000
4 500
5 00 0
5 5 0 0
6000
6500
7000
735 2
NCI A-12A
20" x 24"
4 1/2" Casing
2000
2500
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 07504
NCI A-12B wp02
KOP: 12º/100' : 2630' MD, 2629.85'TVD : 150° RT TF
End Dir : 2647' MD, 2646.85' TVD
Start Dir 4º/100' : 2677' MD, 2676.83'TVD
End Dir : 3543.4' MD, 3484.77' TVD
Start Dir 2.5º/100' : 4643.27' MD, 4373.78'TVD
End Dir : 4766.16' MD, 4475' TVD
Start Dir 2.5º/100' : 5657.61' MD, 5222.63'TVD
End Dir : 6377.61' MD, 5877.68' TVD
Total Depth : 7504.32' MD, 6966' TVD
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: NCIU A-12
Water Depth: 101.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2586723.59 331994.15 61° 4' 36.3150 N 150° 56' 55.6382 W
SURVEY PROGRAM
Date: 2023-05-01T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
410.63 2630.00 N COOK INLET UNIT A-12 Sperry (NCI A-12) 3_CB-Film-GMS
2630.00 3030.00 NCI A-12B wp02 (NCI A-12B) 3_MWD_Interp Azi+Sag
3030.00 7504.32 NCI A-12B wp02 (NCI A-12B) 3_MWD+AX+Sag
FORMATION TOP DETAILS
No formation data is available
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well NCIU A-12, True North
Vertical (TVD) Reference:NCIU A-12A planned RKB @ 126.63usft
Measured Depth Reference:NCIU A-12A planned RKB @ 126.63usft
Calculation Method:Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:NCIU A-12
Wellbore:NCI A-12B
Design:NCI A-12B wp02
CASING DETAILS
TVD TVDSS MD Size Name
6966.00 6839.37 7504.32 4-1/2 4 1/2" Casing
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 2630.00 0.35 185.15 2629.85 -18.94 -6.16 0.00 0.00 -2.08 KOP: 12º/100' : 2630' MD, 2629.85'TVD : 150° RT TF
2 2647.00 1.75 329.49 2646.85 -18.77 -6.29 12.00 150.00 -1.88 End Dir : 2647' MD, 2646.85' TVD
3 2677.00 1.75 329.49 2676.83 -17.98 -6.76 0.00 0.00 -1.14 Start Dir 4º/100' : 2677' MD, 2676.83'TVD
4 3543.40 36.07 294.16 3484.77 101.47 -253.78 4.00 -36.78 273.11 End Dir : 3543.4' MD, 3484.77' TVD
5 4643.27 36.07 294.16 4373.78 366.49 -844.65 0.00 0.00 920.69 Start Dir 2.5º/100' : 4643.27' MD, 4373.78'TVD
6 4766.16 33.00 294.00 4475.00 394.91 -908.25 2.50 -178.40 990.35 End Dir : 4766.16' MD, 4475' TVD
7 5657.61 33.00 294.00 5222.63 592.39 -1351.79 0.00 0.00 1475.87 NCI A-12B wp01 tgt1 Start Dir 2.5º/100' : 5657.61' MD, 5222.63'TVD
8 6377.61 15.00 294.00 5877.68 711.01 -1618.22 2.50 180.00 1767.52 End Dir : 6377.61' MD, 5877.68' TVD
9 7239.94 15.00 294.00 6710.63 801.79 -1822.12 0.00 0.00 1990.70 NCI A-12B wp01 tgt3
10 7504.32 15.00 294.00 6966.00 829.62 -1884.63 0.00 0.00 2059.13 Total Depth : 7504.32' MD, 6966' TVD
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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:Sean McLaughlin
Subject:RE: [EXTERNAL] NCIU A12B PTD application
Date:Friday, July 28, 2023 11:46:00 AM
Sean,
Sounds good. I’ll attach your email to the PTD and add a comment about drilling the Beluga U with
minimum 10.1 ppg.
Thanks
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, July 28, 2023 11:10 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] NCIU A12B PTD application
Bryan,
If agreeable to the State we would like to use the same MW strategy that was used on A-12A. A-12B
is in the same general area and will be drilled to the same horizon as A-12A. The 10.0 ppg pore
pressure is considered a max and not the most likely. Excessive MW’s would like to be avoided
because lost circulation risk in the Beluga is a concern. While drilling A-12A the following MW was
used from the Beluga I to TD (Beluga U).
A-12A:
Report 14 6067' MD finish bringing MW up to 10.1 ppg, trip for bit
Report 15 6067' MD MW 10.1 ppg, Drill into the Beluga I
Report 16 6025’ MD 10.1 ppg. TD well at 7352’ MD with 10.1 ppg MW
Report 17 Back ream out and MW climbs to 10.4 ppg. Run back to bottom and dilute back to 10.1
ppg. Overpulls and pack offs at 5781' and swabbing. Backream area , no swabbing. MW 10.1. Pull
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
to surface on elevators, no swabbing MW 10.1 ppg
Report 18 Run liner circulate 10.1 ppg mud
I have also supplied the Gas data for the A-12A drilling. It shows no connection or trip gas when
drilling to the Beluga U with a 10.1 ppg mud system. This data was monitored closely while drilling
A-12A and gives us confidence drilling with a 10.1 ppg mud on A-12B is prudent.
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, July 27, 2023 4:28 PM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: [EXTERNAL] NCIU A12B PTD application
Sean,
I’m working through the PTD application for this well. All looks good except you’ll need to weight up
the mud to provide some overbalance before penetrating the 10 ppg EMW Beluga U. The PTD
application calls mud weight of 10 ppg below 5836 MD, but the EMW of Beluga U and deeper is 10
ppg EMW. The mud weight needs to have some overbalance to allow for trip margin.
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
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
Dewhurst, Andrew D (OGC)
From:Sean McLaughlin <sean.mclaughlin@hilcorp.com>
Sent:Wednesday, 26 July, 2023 15:26
To:Dewhurst, Andrew D (OGC); Joseph Lastufka
Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC)
Subject:RE: [EXTERNAL] N Cook Inlet Unit-A-12B (PTD 223-053) - Question
Andy,
FortheAͲ12BPTDrequestanddrillingplanIreliedexclusivelyonthedrillingexperiencefromAͲ12A(andtheAͲ14,15,
and16mudweights).TheAͲ12Bwellwillbeabout1800’awayfromtheAͲ12Awellbore.TheAͲ12AMWstrategywas
successfulincontrollingkicksandlosses.TheteamisinterestedinwhattheactualpressureofthedeepBelugais.The
planistogetRFTdataonAͲ12Bifconditionsaregood.
Regards,
Sean
From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>
Sent:Wednesday,July26,20231:31PM
To:SeanMcLaughlin<sean.mclaughlin@hilcorp.com>;JosephLastufka<Joseph.Lastufka@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]NCookInletUnitͲAͲ12B(PTD223Ͳ053)ͲQuestion
Sean,
Sean,
ThanksforreferencetotheAͲ12Awell.Ihavefoundandreviewedyourcommentsfromlastyearregardingthisissue.
Tobeclear,youpreviouslystatedthattheAͲ14,AͲ15,andAͲ16(andAͲ12A)offsetwellsweightedupaccordinglyinthe
lowerBeluga.Butdoyouhaveanyotherdirectevidenceofoverpressureincludingbutnotlimitedtologs,production,
drillingevents,shutͲinpressures,etc.?
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservationCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1245
CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservation
Commission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.
Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,
pleasedeleteit,withoutfirstsavingorforwardingit,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactAndrewDewhurst
at907Ͳ793Ͳ1245orandrew.dewhurst@alaska.gov.
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
2
From:SeanMcLaughlin<sean.mclaughlin@hilcorp.com>
Sent:Wednesday,26July,202312:55
To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;JosephLastufka<Joseph.Lastufka@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:RE:[EXTERNAL]NCookInletUnitͲAͲ12B(PTD223Ͳ053)ͲQuestion
Andy,
WebelievethelowerBelugaisatahigherpressurethantheupperBeluga.Theplanistoweightupto10.0ppgmud
weightpriortodrillingintotheBelugaI.ThisisthesamestrategythatwasusedwhendrillingAͲ12Alastyear.
Regards,
sean
From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>
Sent:Wednesday,July26,202312:46PM
To:SeanMcLaughlin<sean.mclaughlin@hilcorp.com>;JosephLastufka<Joseph.Lastufka@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:[EXTERNAL]NCookInletUnitͲAͲ12B(PTD223Ͳ053)ͲQuestion
Sean,
IamcompletingthereviewoftheNCIUAͲ12Bapplication.Ijusthaveonequestion:
Onpage21oftheapplication,thereisthefollowingstatementabouttheBelugaI:
**EnsureMWof10.0ppgpriortodrillingintotheBelugaI(5836’MD/5376’TVD)**
Wouldyoupleaseexplainthebackgroundonthatcomment?
Thanks,
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservationCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1245
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Commission(AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.
Theunauthorizedreview,useordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,
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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 nogreater
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.
x
North Cook Inlet
223-053
NCIU A-12B
Tertiary Gas
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2
3
JL
C
8
/
7
/
2
0
2
3
