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HomeMy WebLinkAbout225-089Nolan Vlahovich Hilcorp North Slope, LLC
GeoTechnician 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:
Hilcorp North Slope, LLC
Date: 01/09/2026
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-17A
PTD: 225-089
API: 50-883-20188-01-00
CBL 10/09/25
SFTP Transfer – Data Main Folders:
Please include current contact information if different from above.
225-089
T41239
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.01.09 14:41:30 -09'00'
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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: 11/10/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: NCIU A-17A
PTD: 225-089
API: 50-883-20188-01-00
FINAL LWD FORMATION EVALUATION LOGS (09/26/2025 to 10/15/2025)
x BaseStar GR, StrataStar Resistivity, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Pressure While Drilling
x Final Definitive Directional Survey
SFTP Transfer – Data Main Folders:
Please include current contact information if different from above.
225-089
T41094
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.11.12 13:09:34 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/07/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20251107
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf
BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher
BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October
BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf
GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch
GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut
MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey
MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey
MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP
NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut
NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf
NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf
PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT
PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM
PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN
PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM
PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM
PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM
PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN
PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL
SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF
SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF
Please include current contact information if different from above.
T41066
T41067
T41068
T41068
T41069
T41069
T41070
T41071
T41072
T41073
T41074
T41074
T41075
T41076
T41077
T41078
T41079
T41080
T41081
T41082
T41083
T41084
NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf
NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.11.07 15:03:51 -09'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): North Cook Inlet
GL: N/A BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 101 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
4-1/2" L-80 6,726'
4-1/2" L-80 1,476'
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
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
TUBING RECORD
L - 1074 sx / T - 185 sx
CBL 10-9-25, Perf / GPT Logs, LWD ( BST, STS, CTN, ALD, PWD, DDSR)
PACKER SET (MD/TVD)
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
331992 2586730
50-883-20188-01-00September 26, 2025
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
10/10/2025 225-089 / 325-602 / 325-577
N/A
NCIU A-17AOctober 2, 20251249' FNL, 973' FWL, Sec 6, T11N, R9W, SM, AK
126.6'
Tertiary System Gas Pool
ADL 17589
N/A
1,635' MD / 1,571' TVD
443' MD / 443' TVD
7,627' MD / 6,730' TVD
7,315' MD / 6,442' TVD
380' FNL, 1664' FWL, Sec 6, T11N, R9W, SM, AK
63' FNL, 2412' FEL, Sec 6, T11N, R9W, SM, AK
AMOUNT
PULLED
332696
333647
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
GRADE CEMENTING RECORD
2587590
SETTING DEPTH TVD
2587893
TOP HOLE SIZEBOTTOMCASINGWT. PER
FT.
8-1/2"
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
12.6#Surface 1,525'Surface Tieback
Choke Size:
1,446'
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#7,623'
Water-Bbl:
PRODUCTION TEST
10/17/2025
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
1,489'
Tieback Assy.
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl:Water-Bbl:
0 246161
11/1/2025 24
Flow Tubing
24
3232
N/A32320
G
s d 1
0 p
d B P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By James Brooks at 8:58 am, Nov 06, 2025
Completed
10/10/2025
JSB
RBDMS JSB 112825
GMGR29DEC2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel A 5202' 4513'
5185' 4497'
5461' 4751'
5702' 4970'
5874' 5126'
6052' 5288'
6345' 5555'
6561' 5752'
6739' 5915'
6849' 6014'
6955' 6112'
7093' 6237'
7189' 6325'
7617' 6720'
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:
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
Bel Q
Bel R
Bel S
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Report, Definitive Directional Survey
Authorized Title: Drilling Manager
Bel P
Bel F
Bel A
Bel H
Bel N
Bel C
Bel E
Bel J
Bel L
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Bel U
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.11.06 07:10:00 -
09'00'
Sean
McLaughlin
(4311)
Updated by JLL 10/24/25
SCHEMATIC
North Cook Inlet Unit
NCIU A-17A
PTD: 225-089
API: 50-883-20188-01-00
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
30”Conductor – Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 1,635’
(TOW)
4-1/2"Prod Lnr 12.6 L-80 GBCD 3.958”1,489’7,623’
4-1/2"Prod Tieback 12.6 L-80 IBT 3.958”Surf 1,525’
JEWELRY DETAIL
No.Depth
MD
Depth
TVD
ID Item
1 443’443’3.813 Baker Onyx-R5E TRSSV, with 3.813" X Nipple Profile
2 1,009’1,001’-ES Cementer
3 1,413’1,378’3.865 Arctic Lift GLM, PN 21141-11, 1-1/2" pocket (Loaded with a 3/8"
orifice valve)
4 1,469’1,429’3.813 X Nipple 3.813” Profile
5 1,489’1,446’3.960 SLZXP Liner Top Hanger Packer
6 1,525’1,478’3.958 Baker Seal Assembly, 4.75" Extension x 10ft
7 7,315’-CIBP (10/15/25)
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)Btm (TVD)FT Date Status
Bel Aa 5,202’5,208’4,513’4,519’6’10/18/25 Open
Bel Ab 5,211’5,216’4,521’4,526’5’10/18/25 Open
Bel Ac 5,256’5,260’4,563’4,566’4’10/18/25 Open
Bel Ba 5,294’5,299’4,598’4,602’5’10/18/25 Open
Bel Ba1 5,336’5,341’4,636’4,641’5’10/18/25 Open
Bel Bb 5,364’5,369’4,662’4,666’5’10/18/25 Open
Bel Bc 5,378’5,384’4,675’4,680’6’10/18/25 Open
Bel Bd 5,401’5,410’4,696’4,704’9’10/17/25 Open
Bel Be 5,439’5,442’4,730’4,733’3 10/17/25 Open
Bel Ca 5,477’5,483’4,765’4,770’6’10/17/25 Open
Bel Cb 5,540’5,543’4,822’4,825’3’10/17/25 Open
Bel Cc 5,546’5,549’4,828’4,830’3’10/17/25 Open
Bel Da 5,583’5,603’4,861’4,880’20’10/17/25 Open
Bel Db 5,647’5,650’4,920’4,922’3’10/17/25 Open
Bel Ea 5,739’5,749’5,003’5,012’10 10/17/25 Open
Bel Eb 5,768’5,777’5,030’5,038’9’10/17/25 Open
Bel Ec 5,787’5,799’5,047’5,058’12’10/17/25 Open
Bel Ed 5,837‘5,843’5,092’5,098’6’10/16/25 Open
Bel Ee 5,846’5,852’5,100’5,106’6’10/16/25 Open
Bel Fa 5,923’5,933’5,170’5,179’10’10/16/25 Open
Bel G 5,968’5,977’5,211’5,219’9’10/16/25 Open
Bel Ga 6,017’6,023’5,256’5,261’6’10/16/25 Open
Bel Gb 6,026’6,036’5,264’5,273’10’10/16/24 Open
Bel La 6,563’6,577’5,754’5,767’14’10/15/24 Open
Bel Sd 7,321’7,331’6,447’6,456’10’10/14/25 Isolated (10/15/25)
Bel Ta 7,367’7,377’6,489’6,499’10’10/10/25 Isolated (10/15/25)
Bel Tb 7,389’7,399’6,510’6,519’10’10/12/25 Isolated (10/15/25)
Bel Tbl 7,430’7,439’6,548’6,556’9’10/14/25 Isolated (10/15/25)
Bel Tc 7,483’7,493’6,597’6,606’10’10/11/25 Isolated (10/15/25)
Depth Item
3,558’RA Tag
4,079’RA Tag
4,596’RA Tag
5,072’RA Tag
5,562’RA Tag
6,087’10’ Marker Joint
6,572’RA Tag
7,086’10’ Marker Joint
Bel T
1
3
2
RKB = 126.6’
PBTD = 7,538’ / TVD = 6,648’
TD = 7,627’ / TVD = 6,730’
Bel S
Bel La
Bel G
Bel F
Bel E
Bel D
Bel C
Bel B
Bel A
30”
12-1/4”
hole
NCIU A-17
Parent
9-5/8”
8-1/2”
hole
4-1/2”
4/5/6
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface Stg 1 – L – 592 sx / T – 250 sx ; Stg 2 L – 380 sx
4-1/2”Est TOC @ 2630 CBL 10-9-25 L – 1074 sx / T – 185 sx
TOC ~2630' MD from CBL 09-OCT-2025 - mgr
NO RETURNS
ON FIT.
Page 1/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:9/20/2025 End Date:10/8/2025
Report Number
1
Report Start Date
9/20/2025
Report End Date
9/21/2025
Operation
Turn power off to drilling package. R/D service lines, hoses and power cables F/ drilling package – T/ Jack-up. R/D flowline an d overboard line. Remove stairs and
walkways. R/D platform shaker tank.
Backload green iron, shaker tank roofs, service lines, shakers, rig mats and baskets F/ Tyonek platform – T/ MV Mitchell C.
Begin cutting mud wt back F/ 9.9 ppg – T/ 9.0 ppg utilizing centrifuge. Prep East crane on platform for rig move past crane.
Remove clamps from sub-base. Position jacks and hydraulic lines for skidding drilling package. Clean drill deck on platform.
Offload HAK rack decks and backload platform shaker tank to MV Titan. Continue to prepare rig to skid and rotate.
Hold PJSM w/ crews for skidding and rotating operations. Skid to the south 8'. Remove C plates and rotate sub base 90 deg. Install C plates. Continue skidding sub-base
to south side of platform.
Reposition jacks and HPU. Skid drilling package to the East towards leg #1
Report Number
2
Report Start Date
9/21/2025
Report End Date
9/22/2025
Operation
R/D equipment and service lines be able to get over leg #1. Run HYD lines from cantilever to skid unit. Pull skid unit power ca ble F/ drilling package – T/ plug house, C/O
plug on cable.
Skid cantilever towards living quarters 10' to ensure drilling package can get over well.
Reposition service ramp towards rig from platform. Remove stairs and walkways from main deck to platform.
PJSM skidding rig. Skid rig over leg 1. Remove transverse clamp on upper skid package. Transverse rig to south centering up on A-17. Install clamps on upper skid
package.
R/U walkway and service lines to rig. R/U stairs on back on white iron. R/D skid HPU and install earthquake clamps. R/U flow lines and walkways on HAK rack. Continue
R/U wires for rig power.
Install overboard line for scalper shakers. Change die blocks and saver sub on TDS. Offload MV Mitchell C. Begin working on rig acceptance check list.
Service Rig: Grease crown, draw works, ST-80, TDS, choke manifold and manual valves on BOPE. Perform top drive checklist.
Continue to install handrails and safe out rig. Run HP hoses from rig floor to well head room. Clean and drain pollution pans under rig equipment. Clean and organize rig
and platform. Continue to work on rig acceptance checklist.
Report Number
3
Report Start Date
9/22/2025
Report End Date
9/23/2025
Operation
R/U service line to rig floor and check connections. Cut mud weight back in pits F/ 9.5 ppg – T/ 9.0 ppg. Continue to work on rig acceptance checklist.
Bleed PSI off well w/ production. N/D piping and flanges. N/U 1502 flanges on top of tree and casing valve. R/U HP hoses to tubing and annulus.
Fill and test lines to 660PSI/ 5MIN. Open SSSV and valves on tree. INT tubing 270PSI, INT circ pressure 540PSI at 2 BPM. Continue bullhead through IA and tbg. w/ 8.7
ppg FIW @ 3 bpm, FCP 860 psi. 431bbls bullheaded.
Bled down IA w/ .25 bbls bled back. Bled down tbg w/ .11 bbs bled back. Shut in and monitor for 5 mins, 30 psi build.
Bullhead 1.5 tbg vol. down tbg w/ 8.7 ppg FIW @ 3 bpm, ICP 265 psi, FCP 482 psi. 169 bbls bullheaded. Tbg pressure dropped to 50 psi w/ pumps off and shut in.
Monitor for 10 min w/ no pressure gain. Open IA and tbg to fully open choke w/ no gain to trip tank.
R/D HP hoses and 1502 tree cap flange. Set BPV.
N/D production tree and pull to rig floor.
Install R/U line and N/U riser and BOPs.
R/U rig floor to P/U 5” DP and HWDP.
P/U 5” Drill Pipe and HWDP. Rack back in derrick.
Report Number
4
Report Start Date
9/23/2025
Report End Date
9/24/2025
Operation
P/U 5” Drill Pipe and HWDP. Rack back in derrick. 80 stds DP and 6 stds of HWDP.
Install pollution pan/flow box and bell nipple, air up boots.
Build and set test assembly. R/U testing equipment and lines. Fluid pack lines and manifold. R/U hose F/ IA – T/ trip tanks. Open IA and gas migrating to TT. Shit in IA.
R/U hose F/ IA – T/ trip tanks. R/U H.P hose F/ rig floor – T/ IA w/ pressure gauge. 40 psi on IA. Test line to 2000 psi for 5 mins.
Bullhead 300 bbls through IA @ 3 bpm. ICP 212 psi, FCP 405 psi. Pressure stabilized @ 264 psi w/ pumps off. Bleed pressure in 20 psi increments, monitor PSI between
bleeds. Bled down to 10 psi, monitor for 5 min w/ no gain. Fully open choke, monitor @ trip tank, no gain. Remove HP hose F/ IA and install trip tank hose. Monitor well @
trip tank w/ 108 bph loss.
Fluid pack lines and manifold. Obtain shell test after working air out of system to 250/3000 psi for 5 mins.
Test 13 5/8” BOP w/ 5” DP as per Hilcorp test procedure, 250/3000 psi for 5/5 min. Test 6 of 11 completed.
Report Number
5
Report Start Date
9/24/2025
Report End Date
9/25/2025
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151Permit to Drill (PTD) #:225089
Wellbore API/UWI:508832018800100
Page 2/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Completed test 7-11, accumulator draw down test, and gas alarm test.
Tested all BOP components t/250/3000psi f/5min. on chart as per AOGCC/Hilcorp policy w/5" and 4 1/2” test jt and water (Test 1-6 w/5”, test 7-9 w/4 ½”). Annular, 2-7/8 x
5.5 variable rams, blind rams, HCR choke and kill, Manual choke and kill, CMV 1 thru 18, 2 FOSV and 1 Dart, UKV, LKV. Tested gas alarm system, Accumulator draw
down test.
Accumulator test: Closing times:
Initial pressure: 3100psi Annular=15sec.
Final Pressure: 1850psi TPR=12sec. LPR=14sec.
200psi attained: 24sec. Blind rams: 12sec.
Full recovery: 145sec. Choke HCR=1sec.
NO2 Bottle avg.: 2080psi Kill HCR= 1sec.
All tests were witnessed by AOGCC Representative Sully Sullivan.
R/D all BOP testing equipment and test assembly. M/U tubing hanger retrieval assembly.
Retrieve T-bar F/ derrick and latch into BPV. Pressure behind BPV, fill tbg through kill line. Leave BPV and pull T-bar. Close blind rams.
Bullhead 116 bbls through tbg @ 1.8 bpm, ICP 258, FCP 268, Bleed pressure to 0. Well on vacuum.
Retrieve T-bar F/ derrick and pull BPV. RIH w/ tubing hanger retrieval assembly, M/U to hanger.
Attempt to pull hanger staging up to 200k in 10k increments, so success. Back out running tool and TOH. 3 fingers missing on retrieval tool.
L/D retrieval tool and P/U hanger wash tool. TIH and wash hanger @ 5 bpm w/ 220 psi. TOH and L/D hanger wash tool.
P/U hanger retrieval tool and TIH. M/U to hanger and pull hanger w/ 80k. Lock open SSSV. L/D hanger and retrieval tool.
Note: Noticed cement around hanger once on surface.
TOH and L/D 4.5” 12.6 # L-80 Hydril 533 production tbg. and jewelry F/ 4577' – T/ surface. Monitoring hole fill w/ trip tank. 6 0 bph loss rate.
R/D Parker casing running equipment. Clean and organize rig floor.
M/U wear bushing running tool and install wear bushing. Flood test lines.
P/U 9 5/8” cement retainer w/ Tripoint. TIH to 4541’. Set cement retainer @ 4541.
PUW- 130K, SOW- 100K. Set 45K down and pulled 55K. Confirmed retainer set.
Report Number
6
Report Start Date
9/25/2025
Report End Date
9/26/2025
Operation
PJSM w/ Fox and rig crew. Fox pump 5 bbls of water to clear lines. Test lines to 400/ 3500 psi for 5 mins, no drop in pressure. Establish injection rates @ 1 bpm w/ 30
psi, 2 bpm w/ 80 psi, 3 bpm w/ 125 psi, 4 bpm w/ 180 psi, and 5 bpm w/ 210 psi. Establish circ. w/ 5 bbl of fresh water @ 2 bpm. Mix & pump 100 bbl of 15.3 ppg cement
@ 3 bpm w/ 450 psi. Pump 50 bbl of seawater @ 5 bpm w/ 200. Un-sting F/ retainer, pump 18 bbl of seawater @ 5 bpm w/ 200 psi. L/D cement assembly. Cement in
place @ 08:20.
TOH F/ 4541’ – T/ 3937’. Monitoring hole fill w/ trip tank.
CBU @ 3937’, 3 bbpm w/ 300 psi. No cement in returns. R/D cement assembly.
Drop wiper ball and circulate surface – surface, 8 bpm w/ 350 psi.
TOH F/ 3937 – T/ surface. Monitoring hole fill w/ trip tank.
L/D cement retainer running tool.
Clean and clear rig floor.
P/U mill assembly and TIH to 1607'. Monitoring displacement on trip tank. Dress F/ 1607' – T/ 1696' @ 6 bpm w/ 135 psi, 50 rpm, 2k trq.
TIH F/ 1696' – T/ 3683'. Monitoring displacement on trip tank.
Hang Block off, Slip and Cut 71' of drill line. Unhang Block.
Service Rig: Grease crown, draw works, ST-80 and top drive. Perform top drive checklist.
Change shaker screens and install ditch magnets. Calibrate MWD block position.
TIH F/ 3638' – T/ 4047'. Monitoring displacement on trip tank.
Wash F/ 4047’ – T/ 4301’ @ 2 bpm. Tag cement @ 4301’ w/ 8K down.
Tag witnessed by AOGCC representative Austin McLead.
Test casing to 3000 psi for 30 mins.
Test witnessed by AOGCC representative Austin McLead.
TOH F/ 4280’ – T/ surface. Monitoring hole fill w/ trip tank.
L/D mill assembly.
P/U and M/U whipstock assembly as per WIS. Scribe and shallow test MWD as per Halliburton.
TIH w/ 9 5/8” (8.19” ID) whipstock F/ 102’ – T/ 1659’, 3 mins/std. Monitoring displacement on trip tank.
Kelly up and bring on pumps @ 400gpm w/ 921 psi. Cycle pumps and correlate TF, set whip stock as per WIS/Sperry T/ 150deg ROHS. Perform whipstock setting
procedure as per WIS.
Top of window @1635'md, btm of window @1649'md.
Displace well F/ seawater – T/ 9.0 wbm.
Report Number
7
Report Start Date
9/26/2025
Report End Date
9/27/2025
Operation
Displace well F/ seawater – T/ 9.0 wbm, @185gpm, 2000psi.
Mill window as per WIS Rep., F/ 1635' – T/ 1649' @2fph, 400gpm, 1450psi, 90rpm, 1-2k trq off btm, 2-7k trq on btm, P/U=96k, s/o=93k, rot=95k.
Drill new formation F/ 1649’ – T/ 1669’.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 3/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drift window w/ 400 gpm, 1400 psi, 90 rpm, 2-3k trq.
Drift window w/ 400 gpm, 1400 psi, no rotation.
Drift window w/ no pumps and no rotation.
Pump 30 bbls HiVis sweep, reciprocating pipe F/ 1659' – T/ 1630' w/ 400 gpm, 1400 psi. Circulate to ensure 9.0 ppg in/out for FIT.
R/U for FIT, fluid pack choke manifold, choke and kill line. Perform FIT to 475 psi, 14.8 EMW. Pumped in 1.74 bbls and bleed ba ck 0 bbls. Submit results to town and wait
for approval.
TOH F/ 1635' – T/ 102'. Monitoring hole fill w/ trip tank.
PJSM for w/ Halliburton, WIS and rig crew for L/D BHA.
L/D BHA as per Haliburton and WIS.
Note: Lead mill was 1/8” under gauge,
Clean, clear and organize rig floor.
Safety stand down for dropped full water bottle F/ derrick. Discussed the importance of checking work areas before preforming work and insuring that all items brought to
the derrick are brought down when work is complete. Instituted derrick log. Perform full derrick inspection.
P/U BHA #2 as per Haliburton DD/MWD and 1 std of HWDP to 54'. Shallow test MWD. P/U Jar and TIH w/ HWDP to 691’
TIH F/ 691’ – T/ 1608’. Monitoring displacement on trip tank.
Orient tool face to drift through window w/ 400 gpm, 850 psi.
Trouble shoot MWD surface equipment.
Orient tool face to 150 deg R. Drift window F/ 1635’ – T/ 1649’ w/ 400 gpm, 850 psi. Wash to btm F/ 1649’ – T/ 1669’.
Drill / slide 8-1/2'' lateral F/1669' – T/1869'
400gpm, 975psi, 60rpm, 2-3k trq, 2-5k wob, 9.0ppg MW, PUW=102k, SOW=95k, RTW=96K.
Report Number
8
Report Start Date
9/27/2025
Report End Date
9/28/2025
Operation
Circ. 30bbl hi-vis sweep around @1866', 400gpm, 910psi. Returned on time w/25% increase in cuttings. Monitor well-static.
POOH f/1869' t/54', monitoring fill on the TT.
L/D BHA#2 as per DD/MWD, drain motor and break off bit. Bit grade: 1-1-WT-A-E-I-NO-BHA...Pre-job on P/U BHA #3. Clean/clear rig floor.
M/U bit and motor, P/U MWD/LWD tools as per Halliburton. Plug in to syncronize data w/MWD Rep. @ 10:30hrs.
Plug in to syncronize data w/MWD Rep. @ 10:30hrs., Trouble shoot.
Shallow test x2, Pre-job on P/U nukes, Install sources.
RIH f/770' t/1624', orient TF and slide thru window @1635', cont. wasd dwn t/1869', get SPR's.
Drill/slide as per Haliburton DD F/ 1869' – T/ 2239', w/ 460 gpm, 1050 psi, 60 rpm, 2-3k trq, 2-5k WOB, 9.1 MW, 9.6 ecd, P/U 120k, S/O 100k, ROT 110k. Double back
ream each stand and madd pass slides over 20'. Taking surveys every connection.
Drill/slide as per Haliburton DD/wp-04 F/ 2239’ – T/ 2575', w/ 465 gpm, 1150 psi, 60 rpm, 2-3k trq, 1-3k WOB, 9.1 MW, 9.6 ecd, P/U 122k, S/O 105k, ROT 112k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection.
Note: Pumped 30 bbls sweep @ 2379’, Sweep back on time w/ 25% increase in cuttings.
Report Number
9
Report Start Date
9/28/2025
Report End Date
9/29/2025
Operation
Drill/slide as per Haliburton DD/wp-04 F/ 2575’ – T/ 2853', w/ 460 gpm, 1115 psi, 60 rpm, 2-5k trq, 1-3k WOB, 9.1 MW, 9.45 ecd, P/U 135k, S/O 105k, ROT 118k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweephole every 500' or as needed.
Pumped 30 bbls sweep @ 2379’, 460gpm, 1100psi, 60rpm, 3-5k trq. Sweep back 150strokes late w/ 30% increase in cuttings. Flow check well-static...
POOH f/2853' t/1729', monitoring fill on the TT.
RIH f/1729' t/1948', make mad pass f/1945' t/1898', 460gpm, 1038psi, 60rpm, 2-2.5k trq. Cont. RIH f/1898' t/2850', wash dwn las t std-no fill.
Drill/slide as per Haliburton DD/wp-04 F/ 2853’ – T/3132', w/ 460 gpm, 1150 psi, 60 rpm, 5-6k trq, 1-3k WOB, 9.1 MW, 9.52 ecd, P/U 140k, S/O 112k, ROT 125k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Note: Pumped 30 bbls sweep @ 2895’, Sweep back 200 stks late (16 bbls) w/ 25% increase in cuttings.
Drill/slide as per Haliburton DD/wp-04 F/ 3132’ – T/3511', w/ 460 gpm, 1200 psi, 60 rpm, 5-7k trq, 1-5k WOB, 9.1 MW, 9.58 ecd, P/U 150k, S/O 115k, ROT 130k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Note: Pumped 30 bbls sweep @ 3395’, Sweep back 200 stks late (16 bbls) w/ 25% increase in cuttings.
Drill/slide as per Haliburton DD/wp-04 F/ 3511’ – T/3792', w/ 460 gpm, 1200 psi, 60 rpm, 4-7k trq, 1-5k WOB, 9.1 MW, 9.58 ecd, P/U 170k, S/O 115k, ROT 132k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Report Number
10
Report Start Date
9/29/2025
Report End Date
9/30/2025
Operation
Drill/slide as per Haliburton DD/wp-04 F/ 3792’ – T/3890', w/ 460 gpm, 1250 psi, 60 rpm, 4-7k trq, 1-5k WOB, 9.1 MW, 9.58 ecd, P/U 170k, S/O 115k, ROT 132k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
SPR's @3890'md, 9.1ppg
MP#1: 30spm/200psi, 40spm/265psi
MP#2: 30spm/175psi, 40spm/275psi
Pump 30bbl hi-vis sweep @ 460gpm, 1200psi, 60rpm, 5-8k trq. Sweep back on timme w/20% increase in cuttings. Flow check well-static.
Short trip f/3890' t/2853', no issues, monitoring fill on the TT. RIH t/3890', wash dwn last std-no-fill.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 4/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Drill/slide as per Haliburton DD/wp-04 F/ 3890’ – T/4546', w/ 460 gpm, 1465 psi, 60 rpm, 5-10k trq, 1-5k WOB, 9.1 MW, 9.58 ecd, P/U 170k, S/O 115k, ROT 132k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
SPR's @3890'md, 9.1ppg
MP#1: 30spm/200psi, 40spm/265psi
MP#2: 30spm/175psi, 40spm/275psi
Note: Pumped 30 bbls sweep @ 4480’, Sweep back 200 stks late (16 bbls) w/ 15% increase in cuttings.
Drill/slide as per Haliburton DD/wp-04 F/ 4546’ – T/4831’, w/ 460 gpm, 1530 psi, 60 rpm, 5-10k trq, 1-5k WOB, 9.2 MW, 9.88 ecd, P/U 175k, S/O 120k, ROT 140k. Double
back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
SPR's @ 4831'md, 9.2ppg
MP#1: 20spm/200, 30spm/250psi, 40spm/300psi
MP#2: 20spm/200, 30spm/250psi, 40spm/300psi
Circulate 2 Btms Up @ 5956’ w/ 520 gpm, 1900 psi, 60 rpm, 12-15 trq ofb. Rotate and Reciprocate pipe. Pumped 30 bbl high-vis sweep.
Perform Short/Wiper Trip F/ 4831’ – T/ 1624’. Pulled slick on elevators. Monitoring hole fill w/ trip tank. Circulate Btms Up @ 1719, Orient tool face to 152R.
Note: Held trip drill @ 1624’, 1 min response time.
Service Rig: Grease crown, draw works, ST-80 and TDS. Perform daily top drive checklist.
Clean rig floor after wet trip.
Function test BOPE as per AOGCC regulations.
TIH F/ 1624' – T/ 4624'. Monitoring displacement on trip tank.
Report Number
11
Report Start Date
9/30/2025
Report End Date
10/1/2025
Operation
Wash down F/4624' -T/4831' with no fill on bottom.
Pumped 25bbl high vis pill and circ surface to surface
Drill/slide as per Haliburton DD/wp-04 F/ 4831’ – T/5145’, w/ 460 gpm, 1450 psi, 70 rpm, 12-14k trq, 2-11k WOB, 9.2ppg MW, 10ppg ecd, P/U 200k, S/O 125k, ROT 140k.
Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Drill/slide as per Haliburton DD/wp-04 F/ 5145’ – T/5495’, w/ 450 gpm, 1475 psi, 75 rpm, 12-15k trq, 3-8k WOB, 9.3ppg MW, 9.75ppg ecd, P/U 190k, S/O 130k, ROT
160k. Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Drill/slide as per Haliburton DD/wp-04 F/ 5495’ – T/5872’, w/ 450 gpm, 1750 psi, 75 rpm, 15-16k trq, 3-9k WOB, 9.3ppg MW, 10.44ppg ecd, P/U 200k, S/O 130k, ROT
165k. Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
CBU x2 until well cleaned up 450 gpm, 1750 psi, 75 rpm, 15-16k trq, 9.3ppg MW, 10.2ppg ecd
Obtained SPR's
Short trip F/5872' T/4831' monitor well on TT. P/U 230K, S/O 120K
Had multiple 50K over pulls worked down and PU clean.
Short trip F/4831' T/5779' monitor well on TT.
No issues RIH
Wash and ream last stand to BTM 60' of fill on btm.
CBU pumping 25bbl high vis sweep 450 gpm, 1463 psi, 60 rpm, 10-13k trq, 9.3ppg MW, 10.1ppg ecd
Drill/slide as per Haliburton DD/wp-04 F/ 5872’ – T/5966’, w/ 450 gpm, 1750 psi, 75 rpm, 15-16k trq, 3-9k WOB, 9.3ppg MW, 10.44ppg ecd, P/U 230k, S/O 120k, ROT
165k. Tripple back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Report Number
12
Report Start Date
10/1/2025
Report End Date
10/2/2025
Operation
Drill/slide as per Haliburton DD/wp-04 F/ 5966' – T/6344’, w/ 500 gpm, 2090 psi, 75 rpm, 15-18k trq, 3-9k WOB, 9.5ppg MW, 10.64ppg ecd, P/U 235k, S/O 135k, ROT
170k. Tripple back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Drill/slide as per Haliburton DD/wp-04 F/ 6344’ – T/6680’, w/ 480 gpm, 2071 psi, 75 rpm, 14-17k trq, 3-9k WOB, 9.6ppg MW, 10.7ppg ecd, P/U 235k, S/O 140k, ROT
175k. Tripple back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Drill/slide as per Haliburton DD/wp-04 F/ 6680’ – T/6816’, w/ 480 gpm, 2071 psi, 75 rpm, 14-17k trq, 3-9k WOB, 9.6ppg MW, 10.7ppg ecd, P/U 240k, S/O 120k, ROT
165k. Tripple back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Circ 25bbl high vis sweep around getting it back on time and with 20% increase in cuttings at the shakers.
Obatain SPR's and flow check well for 10 min no flow.
POOH for short trip F/6816' T/4831'
50K overpulls at 6105', 5929', 5827', 5730' - 5690', 5549'.
RIH from short trip F/4831' T/ 6724' with no issues.
Wash and ream F/6724' T/6816' with no fill. CBU and getting mostly clay back on bottoms up. Pump 25bbl high vis pill came back on time with a 10% increase at the
shakers.
Drill/slide as per Haliburton DD/wp-04 F/ 6816’ – T/7000’, w/ 480 gpm, 2120 psi, 75 rpm, 14-17k trq, 3-9k WOB, 9.8ppg MW, 10.9ppg ecd, P/U 250k, S/O 135k, ROT
175k. Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Report Number
13
Report Start Date
10/2/2025
Report End Date
10/3/2025
Operation
Drill/slide as per Haliburton DD/wp-04 F/ 7000’ – T/7400’, w/ 450gpm, 2320 psi, 71 rpm, 16-18k trq, 3-10k WOB, 9.8+ppg MW, 11ppg ecd, P/U 290k, S/O 140k, ROT
180k. Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Drill/slide as per Haliburton DD/wp-04 F/ 7400’ – T/7627’, w/ 460 gpm, 2450 psi, 75 rpm, 15-18k trq, 10-12k WOB, 9.9+ppg MW, 11.18ppg ecd, P/U 300k, S/O 150k, ROT
190k. Double back ream each stand and madd pass slides over 20'. Taking surveys every connection. Sweep hole every 500' or as needed.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 5/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Condition and circ well clean w/ 460 gpm, 2450 psi, 75 rpm, 15-18k trq. MW 10ppg.
Flow/ swab check well for 20 mins
CBU getting 234units fo gas back on BUS, decided to increase MW to 10.1ppg.
Racked a stand back after getting 10.1ppg mud around did not see any gas back on BUS.
Spotted LCM out of the pipe.
POOH F/7627' T/1621' with one 100K over pull at 7321' slacked off and wiped clean.
PUW=100K SOW= 100K
Kick while tripping drill response time 42secs shut in and 3mins 57secs total response time.
Service crown, blocks, TD, ST-80, and DW.
RIH F/1621' T/2657 with no issues
Report Number
14
Report Start Date
10/3/2025
Report End Date
10/4/2025
Operation
RIH F/2657' T/7541'
Condition and circ well clean. w/ 460 gpm, 2360 psi, 65 rpm, 15-18k trq. MW 10.1ppg.
POOH F/7627' T/ 594' with no issues. Monitor well on TT taking proper fill.
Dropped 2.38'' rabbit at 2348'.
Monitor well for 10 min no flow at the BHA.
LD BHA #3 as per DD /MWD
Bit graded: 1-1-WT-A-X-I-NO-TD
RU to run liner
MU 4-1/2'' Shoe track assembly and Baker lock connections to the landing collar. Test floats good test.
Run 4-1/2'' liner as per tally T/1170'
Report Number
15
Report Start Date
10/4/2025
Report End Date
10/5/2025
Operation
Run 4-1/2'' liner as per tally F/1170' T/1576'
CBU at window staging pumps up to 7bpm 243psi.
Run 4-1/2'' liner as per tally F/1576' T/3615' with no issues
CBU ar 3615' staging pumps up to 5.5bpm 278psi
Run 4-1/2'' liner as per tally F/3615' T/4903' with no issues
CBU ar 4903' staging pumps up to 5.3bpm 328psi
Run 4-1/2'' liner as per tally F/4903' T/6134' with no issues
CBU ar 6134' staging pumps up to 5.3bpm 328psi
MU SLZXP Packer as per Baker rep.
Circ liner volume through the packer staging pumps up 5bpm 390psi.
Run 4-1/2'' liner in on DP F/6134' T/7555' with no issues.
Wash down F/ 7555' T/7627' tagging up on depth.
LD a double and MU cement head.
Circulate and condition mud for cement job staging up the mud pumps to 5bpm 667psi.
Reciprocating pipe while pumping.
PUW=190K SOW=120K
PJSM with all involved personal. PT cement lines to 4500psi good test. Cement 4-1/2'' liner as per paln. Stopped being able to reciprocate pipe at 319bbls pumped set on
depth @ 7619'. Pump 401.6 bbls of 12.5ppg lead cement getting 100% returns.
Report Number
16
Report Start Date
10/5/2025
Report End Date
10/6/2025
Operation
Continue 4-1/2'' liner cement job. Pumping 40.5 15.3ppg tail cement. Dropped dart and displaced with 10.1ppg mud. Lost returns at 231stks (19bbls) continued pupming
and bumped the plug at 1317 stks. Held 500psi over landing psi. Bled off pressure and checked floats and floats held.
Set packer hanger as per Baker rep. PUW= 90K verifying release.
PU and circ liner top @ 7.5bpm 350psi. Never got cement back to surface.
RD cement and cement hoses.
Drop ball and circ pipe clean @450gpm and 550psi.
POOH LD 5'' DP suckiing a ball through each jt laid down. Doping each end of the JT and installing thread protectors.
LD Baker LRT.
LD 5'' DP from the derrick using the mouse hole. Doping each end of the JT and installing thread protectors.
Pull wear ring.
MU Johnywacker and flush the stack and wellhead. Function BOPE componets and flush stack again.
MU 2-7/8'' tj with test plug. RU test pump.
Install test jt and plug.
Flush and fill BOPE's with water.
Test annular with 2-7/8'' TJ for a charted 250psi low and 2500psi high for 5 mins good test.
Test upper pipe rams with 2-7/8'' JT for a charted 250psi low and 3000psi high for 5 mins good test.
AOGCC rep Jim Regg waived witness.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 6/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
RD test equip and install wear ring.
Preform operational test on 4-1/2'' and 9-5/8'' to 3000psi for a good 10 min test. 3.4bbls to pressure up to 3000psi and got back 3.4bbls.
Moved tong sheeve away from the red tugger sheeve in the derrick.
PU 2-7/8'' motor and mill
RIH PU 2-7/8'' PH6 work string F/ surface T/1049' drifting pipe with 2.25'' rabbit.
Report Number
17
Report Start Date
10/6/2025
Report End Date
10/7/2025
Operation
RIH PU 2-7/8'' PH6 work string F/ 1049' T/1582' drifting pipe with 2.25'' rabbit.
RU and CBU staging pumps up to 3bpm @ 1100psi while reciprocating pipe.
RIH PU 2-7/8'' PH6 work string F/ 1582' T/2600' drifting pipe with 2.25'' rabbit.
Work boat and back load the M/V Titan.
RIH PU 2-7/8'' PH6 work string F/ 2600' T/3688' drifting pipe with 2.25'' rabbit.
RU and circ tbg volume pumping 2bpm @ 850psi while reciprocating pipe.
RIH PU 2-7/8'' PH6 work string F/ 3688' T/5506' drifting pipe with 2.25'' rabbit.
RU and circ tbg volume pumping 2bpm @ 1150psi while reciprocating pipe.
RIH PU 2-7/8'' PH6 work string F/5506' T/6176' drifting pipe with 2.25'' rabbit.
CO elevators to 5'' and continued RIH 2-7/8'' WS on 5'' DP out of the derrick F/6176' T/7407'
Wash and ream down F/7407' T/7538' pumping 1.5bpm @ 925psi.
Tagged up 3K and noticed the motor stalled. Verified depth with another 3K tag and stall.
Dropped pump out sub ball down the pipe with 12bbl high vis spacer and FIW @ 2bpm, 1500psi. Ball seated and sheared out pump out sub at 3000psi. Continued
displacing the well to FIW CBU X3 @ 5bpm, 2950psi.
Flushed all surface and pump lines with FIW.
POOH F/7538' T/6176' racking back 5'' DP.
CO elevator to 2-7/8''
POOH LD 2-7/8'' WS F/6176' T/1598'
Report Number
18
Report Start Date
10/7/2025
Report End Date
10/8/2025
Operation
TOH and LD 2-7/8” PH-6 WS F/ 1598' – T/ surface.
R/D 2-7/8” handling equipment and R/U 5" handling equipment.
P/U & M/U polish mill assembly w/ Baker and TIH t/1453'. Monitoring displacement on trip tank.
Wash f/1453' – t/1527' @ 5 bpm w/250 psi, Tag TOL @ 1494' w/5k down. Polish Seal Bore @ 30 rpm 550k torque as per Baker to 1527', P/U=70k, S/O=70k.
Circulate well clean @ 8 bpm w/ 385 psi.
Service Rig: Grease crown, draw works, ST-80 and top drive. Perform daily top drive checklist.
Prepare rig floor to LD 5” DP.
TOH and LD 5'' DP F/ 1450’ – T/ surface. Wipe inside of pipe w/ wiper ball and vacuum.
B/O and L/D BOT Polish Mill Assy.
M/U wear bushing pulling tool and retrieve wear bushing. P/U Vault washout tool. Wash wellhead profile @ 5 bpm, 75 psi.
Clean, clear and organize rig floor. Prepare for liner run.
B/O pump in assembly and X-Os.
R/U Parker casing running tools and equipment.
Backload pipe onto M/V Titan
PJSM w/ Integra, Baker and rig crew for running 4.5” upper completion.
P/U and M/U seal assembly as per Baker. TIH with 4.5” IBT 12.6# L-80 upper completion tubing as per tally F/ surface’ – T/ 1448’
P/U Landing Jts, space out and tag No-Go @ 1527’ w/ 10k down 2 times. L/D Landing Jts space out assy.
P/U and space out with pup jts. P/U tubing hanger and landing jt. Terminate SSSV control line into hanger. Land out hanger.
Note: MU SSSV and control line, function test 3x valve opened @ 2800 psi, lock open w/5000psi. Space out is 1’ off no-go
Test hanger body seals to 5K for 15 mins. Pull test hanger w/ 40K overpull for 15 mins.
R/U test assembly, manifold and lines. Test tubing to 3000 psi for 30 mins, good test. Test IA and tubing to 3000 psi for 30 mins, good test.
R/D test equipment. Back out and L/D landing jt and hanger running tool.
Back out and L/D landing jts and hanger running tool.
R/D pump assembly and hoses.
R/D Integra casing running tools and equipment.
Clear rig floor of handling equipment, subs, and X-Os
Retrieve T-bar from derrick, Set TWC in tubing hanger. Secure T-bar back in derrick.
Report Number
19
Report Start Date
10/8/2025
Report End Date
10/8/2025
Operation
Clean pollution pan of solids. Blow down TDS, mud lines to rig floor, trip tank lines, choke manifold, choke & kill lines. Blee d down Accumulator. Break bolts on DSA, riser
and BOP.
N/D and remove bell nipple and flow box from rotary. Install R/U lines to TDS.
N/D BOPs from riser and trolly to Aft. N/D riser and L/D.
Clean and prep wellhead and hanger for production tree.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 7/7
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Remove wellhead room hatch and lower production tree onto wellhead. N/U production tree to wellhead. N/U safety valve to production tree.
Test production tree seals and void to 5000 psi.
Preparing to skid drilling package to leg 3.
Field: North Cook Inlet Unit
Sundry #:
State: ALASKA
Rig/Service: 151
Page 1/1
Well Name: NCIU A-17A
Report Printed: 11/5/2025WellViewAdmin@hilcorp.com
Alaska Well Operations Summary
Wellbore API/UWI:508832018800100 Field Name:North Cook Inlet Unit State/Province:ALASKA
Permit to Drill (PTD) #:225089 Sundry #:325-577 Rig Name/No:
Jobs
Actual Start Date:10/9/2025 End Date:
Report Number
1
Report Start Date
10/9/2025
Report End Date
10/10/2025
Last 24hr Summary
IFO. PTW/PJSM w/ AK E-line. Log well with CBL. AOGCC reviewed CBL and granted approval to perforate, Mel Rixse 10/10/25 10:54.
Report Number
2
Report Start Date
10/10/2025
Report End Date
10/11/2025
Last 24hr Summary
RU AK E-line. PT 250/3500 psi. Perforate BEL-T Sand from 7367' - 7377' with well SI.
Report Number
3
Report Start Date
10/11/2025
Report End Date
10/12/2025
Last 24hr Summary
RU N2 lines and PT to 4000 psi. Pump N2 to push fluid - SD at 4000 psi with 44.5 mscf pumped. PT WL PCE 250/4000 psi. Run GPT - FL at 2780'. Perforate BEL-Tc
Sand from 7483' - 7493'. Pump N2 to push fluid - SD at 4000 psi with 19.1 mscf pumped.
Report Number
4
Report Start Date
10/12/2025
Report End Date
10/13/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Run GPT - FL at 3930'. Perforate BEL-Tb Sand from 7389' - 7399'. Pump N2 to push fluid - SD at 4000 psi with 25.9 mscf pumped. Monitor
SITP. Pump N2 again - SD at 4000 psi with 13.1 mscf pumped.
Report Number
5
Report Start Date
10/13/2025
Report End Date
10/14/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Run GPT - FL at 5150'. Pump N2 to push fluid - SD at 4000 psi with 25.2 mscf pumped. Monitor SITP. Pump N2 again - SD at 4000 psi with
10.7 mscf pumped.
Report Number
6
Report Start Date
10/14/2025
Report End Date
10/15/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Run GPT - FL at 6030'. Perforate Bel-TbL from 7430’ - 7439’ and Bel-Sd from 7321’ - 7331’ with well SI. Pump N2 to push fluid - SD at 4000
psi with 37.3 mscf pumped.
Report Number
7
Report Start Date
10/15/2025
Report End Date
10/16/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Run GPT - FL at 6564'. Set CIBP at 7315'. Bleed SITP down to 1650 psi. Perforate BEL-La Sand from 6563' - 6577' with well SI.
Report Number
8
Report Start Date
10/16/2025
Report End Date
10/17/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Run GPT - FL at 6487'. Perforate Bel-Gb (6026' - 6036'), Bel-Ga (6017' - 6023'), Bel-G (5968' - 5977'), Bel-Fa (5923' - 5933'), Bel-Ee (5846' -
5852'), Bel-Ed (5837' - 5843') with well SI. Final SITP 364 psi.
Report Number
9
Report Start Date
10/17/2025
Report End Date
10/18/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Perforate the following intervals with well flowing: Bel-Ec (5787' - 5799'), Bel-Eb (5768' - 5777'), Be l-Ea (5739' - 5749'), Bel-Db (5647' - 5650'),
Bel-Da (5583' - 5603'), Bel-Cc (5546' - 5549'), Bel-Cb (5540' - 5543'), Bel-Ca (5477' - 5483'), Bel-Be (5439' - 442'), Bel-Bd (5401' - 5410').
Report Number
10
Report Start Date
10/18/2025
Report End Date
10/19/2025
Last 24hr Summary
PT WL PCE 250/3500 psi. Perforate the following intervals with well flowing: Bel-Bc (5378' - 5384'), Bel-Bb (5364' - 5369'), Be l-Ba1 (5336' - 5341'), Bel-Ba (5294' - 5299'),
Bel-Ac (5256' - 5260'), Bel-Ab (5211' - 5216'), Bel-Aa (5202' - 5208'). Run flowing GPT survey. Final FTP 269 psi. RDMO E-line.
Page 1/1
Well Name: NCIU A-17A
Report Printed: 11/5/2025
WellViewAdmin@hilcorp.com
Casing
Liner
Wellbore
Wellbore Name:
Sidetrack 1 Total Depth of Wellbore (ftKB):
7,617.00 Original KB/RT Elevation (ft):
126.60
RKB to GL (ft): KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
7,538.0
Casing
Casing Description:
Liner Run Date:
10/4/2025 Set Depth (ftKB):
7,623.00
Casing Weight on Slips (1000lbf):
120,000.0 Pick Up Weight (1000lbf):
190,000.0 Block Weight (1000lbf):
51,000.0
Make-Up Contractor:
Parker Number Hrs to Run (hr):
47.00 Ft/Min (ft/min):
2.70
Run Job:
251-00189 NCIU A-17A Drilling, Drilling -
Drilling, 9/20/2025 06:00
Set Depth (ftKB):
7,623.00 Set Depth (TVD) (ftKB):
Centralizer Detail:
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)
Liner Top Packer 8.43 34.67 1,523.62 1,488.95
Liner 4 1/2 12.60 L-80 6,014.44 7,538.06 1,523.62
Landing Collar 5.07 1.01 7,539.07 7,538.06
Liner 4 1/2 12.60 L-80 40.86 7,579.93 7,539.07
Float Collar 1.31 7,581.24 7,579.93
Liner 4 1/2 12.60 L-80 40.30 7,621.54 7,581.24
Shoe 1.46 7,623.00 7,621.54
Page 1/1
Well Name: NCIU A-17A
Report Printed: 11/5/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Liner, 7,623.00ftKB
Wellbore
Original Hole, N COOK INLET UNIT
A-17
Job
251-00189 NCIU A-17A Drilling, Drilling -
Drilling, 9/20/2025 06:00
Cementing Start Date
10/5/2025
Cementing End Date
10/6/2025
Top Depth (ftKB)
2,630.0
Cement Stages
Stage Number: <Stage Number?>
Description
Liner Cement
Top Depth (ftKB)
2,630.0
Bottom Depth (ftKB)
7,623.0
Top Measurement Method
CBL
Pump Start Date
10/5/2025
Cement in Place At
10/6/2025
Final Circulating Pressure (psi)
1,700.0
Plug Bump Pressure (psi)
2,200.0
Full Return?
No
Returns During Job (%) Volume to Surface (bbl)
374.0
Volume Lost (bbl)
90.0
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
Lead Slurry Lead G 1,074 2.10 12.50 401.6 401.6 4 FOX
Tail Slurry Tail G 185 1.23 15.30 40.5 40.5 4 FOX
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7$ @ 7$ @
@
Benjamin Hand Chelsea Wright 10/06/2025
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:NCI A-17A Date:9/26/2025
Csg Size/Wt/Grade:9.625", 47# L-80 Supervisor:Dambacher/Freeland
Csg Setting Depth:1649'TMD 1575 TVD
Mud Weight:9 ppg LOT / FIT Press =475 psi
LOT / FIT =14.80 Hole Depth =1669'md
Fluid Pumped=1.74 Bbls Volume Back =0.00 bbls
Estimated Pump Output:0.083 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->25858 ->6288
->49234 ->12 551
->613947 ->18 690
->820364 ->24 824
->10 239 36 ->30 1064
->12 260 21 ->36 1299
->14 311 51 ->42 1665
->16 362 51 ->48 2022
->18 400 38 ->54 2408
->20 443 43 ->60 2849
->21 475 32 ->66 3288
->-475 ->
->0 ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0475 ->03288
->1415 ->53265
->2375 ->10 3258
->3351 ->15 3254
->4332 ->20 3251
->5316 ->25 3247
->6301 ->26 3246
->7289 ->27 3245
->8278 ->28 3244
->9268 ->29 3244
->10 258 ->30 3245
->12 242 ->
->14 227 ->
->16 214 ->
->18 203
->19 197
->20 193
NO RETURNS
0
2 4 6
8 10 12 14 16 18 2021
0
6
12
18
24
30
36
42
48
54
60
66
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 10203040506070
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
475
415375351332316301289278268258 242 227 214 203197193
3288 3265 3258 3254 3251 324732463245324432443245
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
ѷ7,617 (proposed)N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Sean McLaughlin
Sean McLaughlin Contact Email: sean.mclaughlin@hilcorp.com
Contact Phone:(907) 223-6784
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
10/5/2025
4-1/2" 12.6#
LTP & SSSV (proposed)ѷ1,401 (MD)ѷ1,401 (TVD) &ѷ400 (MD)ѷ400 (TVD)
±7,617 (proposed)
Perforation Depth MD (ft):
None
±6,216 (proposed) ±6,727 (proposed)4-1/2"
30"
9-5/8"
384'
1,635'
MD
1,630psi
6,870psi
384'
1,571'
384'
1,635'
Length Size
Proposed Pools:
L-80
TVD Burst
±1,401 (proposed)
8,430psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 017589
225-089
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-17A
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Drilling Manager
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Other: Cleanout w/ Rig
North Cook Inlet Tertiary System Gas Same
±6,727 (proposed) ±7,550 (proposed) ±6,665 (proposed) 2,758psi N/A
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
RUSH
By Grace Christianson at 3:42 pm, Oct 02, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.10.02 14:51:54 -
08'00'
Sean
McLaughlin
(4311)
325-602
10-407 initial
completion
DSR-10/2/25MGR02OCT2025
* BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice.
SFD 10/3/2025*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.10.03 09:24:23 -08'00'10/03/25
RBDMS JSB 100625
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Updated by JLL 09/17/25
Proposed Schematic
North Cook Inlet Unit
NCIU A-17A
PTD: 225-089
API: 50-883-20188-01-00
PBTD = ±7,550’ / TVD = ±6,665’
TD = ±7,617’ / TVD = ±6,727’
RKB = 126.6’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 –L –592 sx / T –250 sx ; Stg 2 L –380 sx
4-1/2” Est. TOC @ TOL (40% excess) L –2251 sx / T –205 sx
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30”Conductor –Driven
to Set Depth - - Weld 29” Surf 384’
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf
1,635’
(TOW)
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” ±1,401’ ±7,617’
4-1/2" Prod Tieback 12.6 L-80 EUE 3.958” Surf ±1,401’
130”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth Item
1 ±400 SSSV
21,009’ES Cementer
3 ±1,350 GLM with Orifice gas lift valve
4 ±1,400 X Nipple 3.813” Profile
5 ±1,401’ Seal Stem
6 ±1,401’ Liner hanger / LTP Assembly
8-1/2”
hole
2
3
4/5/6
NCIU A-17
Parent
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Tertiary
System Gas
Pool
±3,510 TBD ±3,471 TBD Future Proposed
PTD 225-089
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):
7,617 (proposed)N/A
Casing Collapse
Structural
Conductor 230psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Eric Dickerman
Contact Email:Eric.Dickerman@hilcorp.com
Contact Phone:(907) 564-4061
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Other: Initial Completion, CT, N2
CO 68A
North Cook Inlet Tertiary System Gas Same
±6,727 (proposed) ±7,550 (proposed) ±6,665 (proposed) 2,758psi N/A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
Operations Manager
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0017589
225-089
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20188-01-00
Hilcorp Alaska, LLC
N Cook Inlet Unit A-17A
Length Size
Proposed Pools:
L-80
TVD Burst
±1,401 (proposed)
8,430psi
MD
1,630psi
6,870psi
384'
±1,601 (proposed)
384'
±1,601 (proposed)
±6,727 (proposed)4-1/2"
30"
9-5/8"
384'
±1,601 (proposed)
±7,617 (proposed)
Perforation Depth MD (ft):
See schematic
±1,401 (proposed)
See schematic
10/15/2025
4-1/2"
LTP & SSSV 1,401 (MD)1,401 (TVD) &400 (MD)400 (TVD)
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
325-577
By Gavin Gluyas at 10:42 am, Sep 24, 2025
Digitally signed by Dan
Marlowe (1267)
DN: cn=Dan Marlowe (1267)
Date: 2025.09.24 09:57:47 -
08'00'
Dan Marlowe
(1267)
10-407
DSR-9/24/25TS 10/7/25
* Service coil BOPE pressure test to 3500 psi. 48 hour notice.
MGR15OCT2025
10/16/2025
Initial Completion
Well: North Cook Inlet Unit A-17A
Well Name:NCIU A-17A API Number:50-883-20188-01-00
Current Status:New drill gas well Leg:Leg #1 (NW corner)
Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:225-089
First Call Engineer:Eric Dickerman (907) 564-4061
Second Call Engineer:Casey Morse (907) 777-8322
Maximum Expected BHP:3,431 psi at 6,727 TVD - 0.51 psi/ft 10-401 Section 26, pg 34
Max. Potential Surface Pressure: 2,758 psi MPSP -0.1 psi/ft gas grad. to surface 10-401 Section 26, pg 34
Field/Pool: North Cook Inlet Unit, Tertiary System Gas Pool
Applicable Frac Gradient: 0.78 psi/ft using 15.0 ppg EMW 10-401 Section 26, pg 34
Shallowest Allowable Perf TVD: MPSP/(Frac grad. Gas grad.) = 2,758 psi / (0.78 0.1 psi/ft) = 4,055 TVD
Brief Well Summary:
NCIU A-17A is planned to be a rotary sidetrack drilled by Spartan 151. The primary target is the Beluga sands,
with a future option to test the Sterling sands. The well is planned to exit the existing 9-5/8 casing at 1,600
then drill an 8-1/2 production hole to a target TD of ± 7,617 MD. After milling the window, an FIT is planned
to 14.8 ppg. The production interval will be cased with a 4-1/2 production liner. The upper completion is
planned to be a 4-1/2 tieback.
Objective:
Initial completion post rig.Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD
approval from AOGCC before perforating.
Wellbore information:
A 9-5/8 x 4-1/2 liner lap test, a 4-1/2 MIT-T, and a 9-5/8 x 4-1/2 MIT-IA will be performed to 3,000
psi on the rig per the approved 10-401.
The well will be completed with a tubing retrievable subsurface safety valve set at ± 400.
Plan to run tubing string with a live gas lift valve.
North Cook Inlet Unit, Tertiary System Gas Pool top = Top of Sterling sands, estimated at 3,510 MD /
3,471 TVD from prognosis.
North Cook Inlet Unit, Tertiary System Gas Pool Bottom = Base of Beluga sands.
Initial Completion
Well: North Cook Inlet Unit A-17A
Coiled Tubing and Eline Procedure:
1. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
2. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48 hr witness notification for BOP test.
3. MU cleanout BHA.
4. RIH to PBTD and circulate the well from drilling mud to filtered inlet water.
5. Standback coiled tubing.
6. MIRU Eline.
7. Pressure test PCE to 250 psi low / 3,500 psi high.
8. Log CBL from PBTD to top of production liner (estimated at 1,400).
a. Submit CBL to AOGCC for approval prior to perforating.
9. RDMO Eline.
10. Stab coiled tubing lubricator back on well.
11. Pressure test PCE to 250 psi low / 3,500 psi high.
12. If Eline is unable to log CBL, RIH with CBL toolstring in carrier then log from PBTD to top of production
liner (estimated at 1,400). Submit CBL to AOGCC for approval.
13. RIH and blow well dry with nitrogen.
14. RDMO CTU.
Eline Perf procedure Pending AOGCC approval after CBL review
15. MIRU Eline and Nitrogen package.
16. Pressure test PCE and N2 treating iron to 250 psi low / 3,500 psi high.
17. Confirm CBL, actual Pool top and bottom, and shallowest allowable perf TVD approval from AOGCC
before perforating.
18. Perforate target gas sands in the North Cook Inlet Unit Tertiary Systems Gas Pool per Reservoir
Engineer/Geologist.
a. Top pool = 3,510 MD / 3,471 TVD (from prognosis).
b. Bottom pool = deeper than TD.
c. Use Nitrogen to pressurize wellbore to target shooting pressure.
19. RDMO Eline and Nitrogen.
CONTINGENCY Eline plug/patch: (if any zone makes unwanted solids or water)
20. RU Nitrogen to tubing and pressure test treating iron to 250 psi low / 3,500 psi high.
21. Pressure up on tubing to displace water back into formation.
22. MIRU Eline.
23. Pressure test PCE to 250 psi low / 3,500 psi high.
24. Set 4-1/2 CIBP or patch to shut off unwanted interval per Operations Engineer.
25. RDMO Eline and Nitrogen.
CONTINGENCY Coiled Tubing Cleanout: (if any zone brings in excessive fill and needs to be cleaned out)
26. MIRU Fox Offshore Coiled Tubing Unit #9 and pressure control equipment.
27. Pressure test BOP and PCE to 250 psi low / 3,500 psi high.
a. Provide AOGCC with 48 hr witness notification for BOP test.
Initial Completion
Well: North Cook Inlet Unit A-17A
28. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to target depth per Operations Engineer.
a. Working fluid will be 6% KCl (8.6 ppg).
b. Take returns to surface from the coiled tubing by 4-1/2 annulus.
c. Add foam and nitrogen as necessary to carry solids to surface.
29. RIH and blow well dry with nitrogen.
30. RDMO CTU.
Operations:
31. Perform SVS test within 5 days.
Attachments:
1. Proposed Wellbore Schematic
2. CT BOP Drawing
3. Nitrogen procedure
Updated by JLL 09/17/25
Proposed Schematic
North Cook Inlet Unit
NCIU A-17A
PTD: 225-089
API: 50-883-20188-01-00
PBTD = ±7,550 / TVD = ±6,665
TD = ±7,617 / TVD = ±6,727
RKB = 126.6
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface Stg 1 L 592 sx / T 250 sx ; Stg 2 L 380 sx
4-1/2 Est. TOC @ TOL (40% excess) L 2251 sx / T 205 sx
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
30Conductor Driven
to Set Depth - - Weld 29 Surf 384
9-5/8" Surf Csg 47 L-80 TXP 8.681 Surf
±1,601
(TOW)
4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958 ±1,401 ±7,617
4-1/2" Prod Tieback 12.6 L-80 EUE 3.958 Surf ±1,401
130
9-5/8
12-1/4
hole
4-1/2
JEWELRY DETAIL
No. Depth Item
1 ±400 SSSV
2 1,009 ES Cementer
3 ±1,350 GLM with Orifice gas lift valve
4 ±1,400 X Nipple 3.813 Profile
5 ±1,401 Seal Stem
6 ±1,401 Liner hanger / LTP Assembly
8-1/2
hole
2
3
4/5/6
NCIU A-17
Parent
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD)FT Date Status
Tertiary
System Gas
Pool
±3,510 TBD ±3,471 TBD Future Proposed
KLU A-1
Well Head Rig Up
1
1
1
1
4 1/16" 15K Lubricator - 10 ft
100" Gooseneck
HR680 Injector Head
4 1/16" 10K Flow Cross, 2" 1502 10k Flanged
Valves
4 1/16" 15K Lubricator - 10 ft
API Flange Adapter 10K to 5K for riser/wellhead
Hydraulic Stripper 4 1/6" 15K
API Bowen CB56 15K
4 1/16" 10K Combi BOPs
Blind/Shear Ram
Pipe/Slip Ram
4 1/16" 10K bottom flange
4 1/16" 5K flanged Riser - 10 ft if necessary
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
09/23/2016 FINAL v-offshore Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Facility Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data
Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well
that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank.
From:Starns, Ted C (OGC)
To:"Eric.Dickerman@hilcorp.com"
Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Rixse, Melvin G (OGC)
Subject:NCIU A-17A (PTD 225-089) sundry 325-577 data request
Date:Friday, October 3, 2025 2:20:00 PM
Good afternoon Eric,
Can you please send field quality copies of any open-hole logs you have run on the NCIU
A-17A and planned perforation depths so I may process your sundry request?
An as-drilled directional survey and formation tops will also be helpful.
If I could receive the logs in .PDF and .las format, and perforations and tops in .xls or .txt
format, it will expedite my review.
Please note that these field quality logs will only be used to process this sundry and will
not satisfy final reporting requirements of 20 AAC 25.071.
Have good weekend,
Ted
Ted Starns
Petroleum Geologist
AOGCC
907-793-1225 (office)
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:Casey Morse
To:Starns, Ted C (OGC); Rixse, Melvin G (OGC)
Cc:Eric Dickerman; Dewhurst, Andrew D (OGC)
Subject:NCIU A-17A Perf Sundry (PTD 225-089)
Date:Saturday, October 4, 2025 6:28:00 PM
Attachments:NCIU A-17A FE Data Daily RT.las
NCIU A-17A Surveys.las
NCIU A-17A Surveys.pdf
NCIU A-17A LWD RT 5in TVD.pdf
NCIU A-17A LWD RT 2in TVD.pdf
NCIU A-17A LWD RT 5in MD.pdf
NCIU A-17A LWD RT 2in MD.pdf
NCIU A-17A LWD RT PWD VIB.pdf
NCIU A-17A - Well Tops.xlsx
Mr. Starnes and Mr. Rixse,
Please see the attached directional survey and LWD formation logs for NCIU A-17A. Also attached
are field prints of the open hole logs from the drilling and a table of the formation tops.
TD was called on 10/2. The crew was running the 4-1/2 liner today, so Ill have to report back to
you on the cement job as the crew completes the cementing in the coming days. As part of the
sundry, we plan to log a CBL, so I will send that as well when complete.
On 9/20 an FIT was performed to a 14.8 ppg equivalent mud weight (0.77 psi/ft).
Maximum possible surface pressure = 2,758 psi from PTD
Shallowest allowable perf TVD = 2,758 psi / (0.77 psi/ft 0.1 psi/ft) = 4,116 tvd.
Top potential perf interval = 5,180 md / 4,493 tvd
Bottom potential perf interval = 7,547 md / 6,656 tvd
Please let me know if you have any questions.
Casey Morse
Operations Engineer
Cook Inlet Offshore
Hilcorp Alaska, LLC
(907) 777-8322
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
Starns, Ted C (OGC)
From:Casey Morse <casey.morse@hilcorp.com>
Sent:Saturday, October 4, 2025 6:27 PM
To:Starns, Ted C (OGC); Rixse, Melvin G (OGC)
Cc:Eric Dickerman; Dewhurst, Andrew D (OGC)
Subject:NCIU A-17A Perf Sundry (PTD 225-089)
Attachments:NCIU A-17A FE Data Daily RT.las; NCIU A-17A Surveys.las; NCIU A-17A Surveys.pdf;
NCIU A-17A LWD RT 5in TVD.pdf; NCIU A-17A LWD RT 2in TVD.pdf; NCIU A-17A LWD
RT 5in MD.pdf; NCIU A-17A LWD RT 2in MD.pdf; NCIU A-17A LWD RT PWD VIB.pdf;
NCIU A-17A - Well Tops.xlsx
Mr. Starnes and Mr. Rixse,
Please see the a ached direc onal survey and LWD forma on logs for NCIU A-17A. Also a ached are eld prints of the
open hole logs from the drilling and a table of the forma on tops.
TD was called on 10/2. The crew was running the 4-1/2 liner today, so Ill have to report back to you on the cement job
as the crew completes the cemen ng in the coming days. As part of the sundry, we plan to log a CBL, so I will send that
as well when complete.
On 9/20 an FIT was performed to a 14.8 ppg equivalent mud weight (0.77 psi/).
Maximum possible surface pressure = 2,758 psi from PTD
Shallowest allowable perf TVD = 2,758 psi / (0.77 psi/ft 0.1 psi/ft) = 4,116 tvd.
Top potential perf interval = 5,180 md / 4,493 tvd
Bottom potential perf interval = 7,547 md / 6,656 tvd
Please let me know if you have any ques ons.
Casey Morse
Operations Engineer
Cook Inlet O shore
Hilcorp Alaska, LLC
(907) 777-8322
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.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: North Cook Inlet Field, Tertiary System Gas Oil, NCIU A-17A
Hilcorp Alaska, LLC
Permit to Drill Number: 225-089
Surface Location: 1249' FNL, 973' FWL, Sec 6, T11N, R9W, SM, AK
Bottomhole Location: 69' FNL, 2404' FEL, Sec 6, T11N, R9W, SM, AK
Dear Mr. McLaughlin:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
*UHJRU\ &.:LOVRQ
Commissioner
DATED this 1th day of September 2025.
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.11 08:41:54 -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: 7,617' TVD: 6,727'
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-331992 y-2586730 Zone-4 N/A to Same Pool:1158' to NCIU A-10B
16. Deviated wells:Kickoff depth: 3,300 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
8-1/2" 4-1/2" 12.6# L-80 GBCD 6,216' 1,401' 1,367' 7,617' 6,727'
Tieback 4-1/2" 12.6# L-80 EUE 1,401' Surface Surface 1,401' 1,367'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
7621'
TVD
384'
3449'
6999'
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-17A
North Cook Inlet Unit
Tertiary System Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
To be plugged
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
2758
648' FNL, 836' FWL, Sec 6, T11N, R9W, SM, AK
69' FNL, 2404' FEL, Sec 6, T11N, R9W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1249' FNL, 973' FWL, Sec 6, T11N, R9W, SM, AK ADL 17589
18. Casing Program:Top - Setting Depth - BottomSpecifications
3431
GL / BF Elevation above MSL (ft):
Plugs (measured):
(including stage data)
L - 2251 ft3 T - 205 ft3
Tieback Assy.
7621'5389'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
9290'7000'
LengthCasing
7621'
Size
To be plugged
Conductor/Structural 30"384'
Authorized Title:
Authorized Signature:
4-1/2"
Authorized Name:
Production
Liner 4712'
Intermediate
Driven 384'
4743'9-5/8"1222 sx
Drilling Manager
Sean Mclaughlin
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
4743'
880 sx
9/15/2025
6872' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
9289'
5002
Cement Volume MD
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 2:26 pm, Aug 19, 2025
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.08.19 14:22:13 -
08'00'
Sean
McLaughlin
(4311)
* BOPE test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC.
* State witness tag (TOC ~4100' MD) and pressure test (3000 psi) of
cement abandonment plug. 48 hour notice.
* Shallow surface casing shoe may result in limited kick tolerance which
could affect approved TD. Email casing test and FIT digital data to AOGCC for alternate approved TD if
FIT of 14.8 ppge is not assured.
MGR10SEP2025
1,600' MD
50-883-20188-01-00
DSR-8/19/25A.Dewhurst 08SEP25
225-089
JLC 9/10/2025
Gregory C Wilson Digitally signed by Gregory C Wilson
Date: 2025.09.11 08:41:33 -08'00'
09/11/25
09/11/25
RBDMS JSB 091525
A-17A Drilling Program
Tyonek
Sean McLaughlin
PTD Program
August 19, 2025
NCI A-17A
Drilling Program
Contents
1. Well Summary.....................................................................................................................................2
2. Management of Change Information................................................................................................3
3. Tubular Program:...............................................................................................................................4
4. Drill Pipe Information:.......................................................................................................................4
5. Internal Reporting Requirements.....................................................................................................5
6. Current Wellbore Schematic.............................................................................................................6
7. Planned Wellbore Schematic (see sundry for decomplete schematic) ...........................................8
8. Drilling Summary...............................................................................................................................9
9. Mandatory Regulatory Compliance / Notifications.......................................................................10
10. BOP N/U and Test.............................................................................................................................12
11. Preparatory Work and Mud Program............................................................................................12
12. Decomplete, Plug parent wellbore...................................................................................................14
13. Set Whipstock, Mill Window...........................................................................................................14
14. Drill 8-1/2” Hole Section...................................................................................................................15
15. Run 4-1/2” Production Liner...........................................................................................................17
16. Cement 4-1/2” Production Liner.....................................................................................................19
17. Wellbore Clean Up & Displacement...............................................................................................22
18. Run Completion Assembly...............................................................................................................22
19. BOP Schematic..................................................................................................................................23
20. Wellhead Schematic..........................................................................................................................24
21. Anticipated Drilling Hazards...........................................................................................................25
22. Jack up position ................................................................................................................................26
23. FIT Procedure...................................................................................................................................27
24. Choke Manifold Schematic..............................................................................................................28
25. Casing Design Information ..............................................................................................................30
26. 8-1/2” Hole Section MASP...............................................................................................................31
27. Plot (NAD 27) (Governmental Sections).........................................................................................32
28. Slot Diagram......................................................................................................................................33
29. Directional Program (wp02) - Attached separately......................................................................34
Page 2 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
1. Well Summary
Well NCI A-17A
Drilling Rig Rig 151
Leg 1
Directional plan wp02
Pad & Old Well Designation Sidetrack of existing well A-17 (PTD#223-031)
Planned Completion Type 4-1/2” 12.6# Liner, 4-1/2” Tubing Comp
Target Reservoir(s)Beluga A-T
Kick off point 1600’ MD
Planned Well TD, MD / TVD 7617’ MD / 6727’ TVD
PBTD, MD 7517’ MD
AFE Number
AFE Days
AFE Drilling Amount
Work String 4.5” 16.6# S-135 CDS40 or 5” 19.5# S135 NC50
RKB – AMSL 126.63’
MSL to ML 74.1’
Page 3 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
2. Management of Change Information
Date: August 18, 2025
Subject: Changes to Approved Permit to Drill
File #: NCI A-17A Drilling Program
Significant modifications to Drilling Program for PTD will be documented and approved below. Significant
changes to an approved PTD will be communicated and approved by the AOGCC prior to continuing forward
with work.
Sec Page Date Procedure Change Approved By
Approval:
Drilling Manager Date
Prepared:
Engineer Date
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3. Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Prod
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288
** Liner must overlap casing by at least 100’.
4. Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
or
5”4.276 3.25 6.625 19.5 S-135 NC50 15,638 10,029 560k
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5. Internal Reporting Requirements
1. Fill out daily drilling report and cost report.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Capture any out-of-scope work as NPT. This helps later when aggregating end of well reports.
2. Afternoon Updates
x Submit a short operations update every day to Kenai/CIO Drilling
<KenaiCIODrilling@hilcorp.com>
3. EHS Incident Reporting
x Notify EHS field coordinator.
i. Garrett St. Clair: C: (907) 252-7780
x Spills:
i. Adrian Kersten: C: 907-564-4820
ii. Sean Mclaughlin
x Report ALL spills to the water within 15 minutes.
x Submit Hilcorp Incident report to contacts above within 24 hrs
4. Casing Tally
x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com and cdinger@hilcorp.com
5. Casing and Cmt report
x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com and
cdinger@hilcorp.com
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6. Current Wellbore Schematic
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7. Planned Wellbore Schematic (see sundry for decomplete schematic)
Top of 9-5/8" Whipstock
at ~1600' MD.
Sundry 325-490
NCIU A-17
9-5/8" casing shoe 4743' MD
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8. Drilling Summary
A-17 is a low rate gas well that will benefit from relocating the wellbore. Well planned to be sidetracked to
down-space the producing Beluga formations.
The 4-1/2” tubing will be pulled prior to running a 9-5/8” cement retainer. The parent will be plugged with
cement above and below the retainer. The wellbore will be sidetracked and new wellbore drilled to 7617’. A
4-1/2” L-80 prod liner will be run, cemented, and perforated based on data obtained while drilling the interval.
The well will be completed with a 4-1/2” gas lift tie-back completion.
Drilling operations are expected to commence approximately September 15, 2025.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
General sequence of operations pertaining to this drilling operation:
Rig
1. Rig 151 will MIRU over Leg 1, Well A-17 (Sundry Ļ)
2. NU BOPE and test to 3000 psi. (MASP 2758psi)
3. Pull 4-1/2” tubing from the PBR at 4577’
4. Set 9-5/8’ 47# cement retainer at 4500’, plug parent well with cement
5. WOC, Tag cement (AOGCC Notification Required), Test 9-5/8” casing to 3000 psi.
6. Set 9-5/8” whipstock at 1600’ and 150R. Swap well to 9.0 ppg LSND mud.
7. Mill window with 20’ of new formation.(Permit To Drill Ļ)
8. Perform FIT to 14.8 ppg EMW
9. PU 6-3/4” motor drilling assembly and TIH to window.
10. Drill 8-1/2” production hole to 7617’ MD, performing short trips as needed
11. RIH w/ 4-1/2” liner. Set liner and cement.
12. Perform liner lap test to 3000 psi.
13. Run 4-1/2” completion.
14. Land hanger and test.
15. ND BOPE, NU tree and test void
Reservoir Evaluation Plan:
1. Production Hole: Triple Combo LWD
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9. Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling. Ensure to provide AOGCC 48 hrs
notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
o The highest reservoir pressure expected is 3431 psi in the Beluga S/T sands (6727' TVD). MASP
is 2758 psi with 0.1psi/ft gas in the wellbore.
o A casing test to 3000 psi is planned after plugging the parent
x Rated Working Pressure (RWP) the BOPE and wellhead must meet or exceed: 3000 psi.
x If the BOP is used to shut in on the well in a well control situation,ALL BOP components utilized
for well control must be tested prior to the next trip into the wellbore. This pressure test will be
charted same as the 14 day BOP test.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
8-1/2”
x 13-5/8” Shaffer 5M annular
x 13-5/8” 5M Shaffer SL Double gate
x Blind ram in bottom cavity
x Mud cross
x 13-5/8” 5M Shaffer SL single gate
x 3-1/16” 5M Choke Manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Masco 7 station, 15 bottle, 3000 psi closing unit with two air pumps, a triplex
electric driven pump
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to full BOPE test.
x Any other notifications required in APD conditions of approval.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / (C): 907-250-9193 / Email:bryan.mclellan@alaska.gov
Melvin Rixse / Petroleum Engineer / (O): 907-793-1231 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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10. BOP N/U and Test
1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug
2. N/U to 11” 5M
3. N/U 13-5/8” x 5M BOP as follows (top down):
x 13-5/8” x 5M Shaffer annular BOP.
x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm
cavity)
x 13-5/8” mud cross
x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR)
x N/U pitcher nipple, install flowline.
x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master
valve”.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
x 11” 5M Clamp hub adapter required
4. Test BOPE.
x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not
build up beneath the TWC. Confirm the correct valves are opened!!!
x Test VBRs on 4.5” and 5” (if using 5” DP)test joints (3000 psi)
x Test Annular on 4.5” test joint (2500 psi)
x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE.
5. Pull Blanking plug and BPV
11. Preparatory Work and Mud Program
1. Mix 9.0 WBM mud for 8-1/2” hole section.
2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s)
x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422
gpm at 115 spm.
x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps.
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3. 8-1/2” Production hole mud program summary:
x Primary weighting material to be used for the hole section will be barite to minimize solids.
Ensure enough barite is on location to weight up the active system 1ppg above highest
anticipated MW in the event of a well control situation.
x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, and Toolpusher office.
System Type:LNSD WBM
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1600’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 11.0
System Formulation: 2% KCL/BDF-976/GEM GP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
DEXTRID LT
PAC L
BDF-976
GEM GP
BARACARB 5/25/50
STEELSEAL 50/100/400
BAROFIBRE
BAROTROL PLUS
SOLTEX
BAROID 41
ALDACIDE-G
0.905 bbl
7 ppb
0.2 ppb (9 pH)
1.0 ppb (as required 18 YP)
1-2 ppb
1 ppb
4 ppb
1.0% by volume
5 ppb (1.7 ppb of each)
5 ppb (1.7 ppb of each)
1.7 ppb
4.0 ppb
2 – 4 ppb
as needed
0.1 ppb
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4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated
BHP’s from formations capable of producing fluids or gas and formations which could require mud
weights for hole stabilization.
5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced
and have the challenge to mitigate lost circulation.
12. Decomplete, Plug parent wellbore
Operation Steps:
1. Pull 4-1/2” tubing from PBR at 4577’.
2. Set wear bushing in wellhead. Ensure ID of wear bushing > 8-1/2”.
3. PU 9-5/8” cement retainer and set at 4500’
4. Pump 70 bbls of 15.3# below the retainer
x ~50 bbl to bottom perforation and 20 bbls excess
x 4-1/2” CBP at 7629’ with 8’ cement and fill above, last tag at 7536’
x 4-1/2” CBP at 7665’
x 4-1/2” CIBP at 8665’
5. Unsting from retainer and lay in 30 bbls of cement above the retainer (~400’)
6. WOC, Tag cement (AOGCC notification required for opportunity to witness)
7. Pressure test 9-5/8” casing to 3000 psi.
13. Set Whipstock, Mill Window
Operation Steps:
1. Make up the WIS hydraulic set Whipstock.
2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock
assembly
¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly.
¾Avoid sudden starts and stops while running the whipstock.
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¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch
the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly
when releasing the work string to RIH. These precautions are required to avoid any weakening of the
whipstock shear mechanisms and / or to avoid part / preset on the packer.
3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg ROHS.
4. Set the top of the whipstock at ~1600’ MD
x 9-5/8” Collars per casing tally.
Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
5. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to at least 14.8 ppg.
¾**Assuming the kick zone is at TD, a FIT of 14.8 ppg EMW gives a Kick Tolerance volume of 16 bbls with
10.3 ppg mud weight (swab kick due to max expected mud weight).
6. POOH and LD milling assembly
¾Once out of the hole, inspect mill gauge and record.
¾Flow check well for 10 minutes to confirm no flow:
¾Before pulling off bottom.
¾Before pulling the BHA through the BOPE.
7. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
14. Drill 8-1/2” Hole Section
Email casing test and FIT digital data to AOGCC upon completion of FIT. - mgr
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1. PU 7800’or 4-1/2” or 5” (5” preferred)Drill pipe for drilling 8-1/2” hole section
2. P/U 6-3/4” Sperry Sun motor drilling assy
x Drill 200’ of rathole prior to picking up LWD to avoid tool damage across the window.
3. Ensure BHA Components have been inspected previously.
4. Drift & caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
5. Ensure TF offset is measured accurately and entered correctly into the MWD software.
6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~450 gpm.
7. Production section will be drilled with a motor. Must keep up with 4 deg/100 DLS in the build and
drop sections of the wellbore.
8. Primary bit will be the 8-1/2” Hycalog A1. Ensure to have a backup PDC bit available on location.
9. TIH to window. Shallow test MWD on trip in.
10. Circulate well with 9.0 ppg LNSD to warm up mud until good 9.0 ppg in and out.
11. Drill approx. 200’ rat hole to accommodate the LWD assembly. Ream window as needed to assure
there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and
pass through shoe checking for drag.
12. Circulate Bottoms Up until MW in = MW out.
13. Trip to surface to pick up triple combo (DEN, POR, RES).
14. Drill 8-1/2” hole to 7617’ 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 pressures low when tripping due to Kick Tolerance. Reduce pull speed and
pump out of hole if necessary.
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 Mud weight to be at least 10.1 ppg at 7000’ MD
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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. TOH with drilling assembly, handle BHA as appropriate.
15. Run 4-1/2” Production Liner
1. R/U Baker 4-1/2” liner running equipment.
x Ensure DP crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted and tally verified prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x Landing collar pup bucked up.
x Centralizers will be run on 4-1/2” liner
x Ensure proper operation of float shoe & FC.
4. Continue running 4-1/2” production liner to TD
x Short joint run every 1000’
x Fill liner while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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5. Ensure to run enough liner to provide at least 100’ overlap inside casing. Ensure setting sleeve will not
be set in a connection.
6. Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make
sure it coincides with the pipe tally.
7. M/U Baker ZXP liner top packer. Fill liner tieback sleeve with “XANPLEX”, ensure mixture is thin
enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up.
8. RIH one stand and circulate a minimum of one liner volume. Note weight of liner.
9. RIH w/ liner on DP no faster than 1 min / stand. Watch displacement carefully and avoid surging the
hole. Slow down running speed if necessary.
10. M/U top drive and fill pipe while lowering string every 10 stands.
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11. Set slowly in and pull slowly out of slips.
12. Circulate 1-1/2 drill pipe and liner volume at 9-5/8” window prior to going into open hole. Stage pumps
up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure.
13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, &
30 rpm.
14. Continue to fill the string every 10 joints while running liner in open hole. Do not stop to fill casing.
15. P/U the cmt stand and tag bottom with the liner shoe. P/U 2’ off bottom. Note slack-off and pick-up
weights. Record rotating torque values at 10, 20, & 30 rpm.
16. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting
pressure. Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling
fluid by adding water and thinners.
17. Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for
cementing.
16. Cement 4-1/2” Production Liner
1. Hold a pre-job safety meeting over the upcoming cmt operations.
2. Attempt to reciprocate the casing during cmt operations until hole gets sticky.
3. Pump 15 bbls 12.5 ppg spacer.
4. Test surface cmt lines to 4500 psi.
5. Pump remaining 10 bbls 12.5 ppg spacer.
6. Mix and pump per below recipe and volume with xx lbs/bbl of loss circulation fiber. Please
independently verify cement volume with actual inputs. Ensure cmt is pumped at designed weight. Job
is designed to pump 40% OH excess but if wellbore conditions dictate otherwise decrease or increase
excess volumes. Cement volume is designed to bring cement to TOL.
7. Displacement fluid will be CLEAN drilling mud. Program displacement volume dependent on depth
and pipe size. Please independently verify with actual inputs.
Slurry Information:
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8. Drop DP dart and displace with clean 10.3 ppg WBM.
9. Pump cement at max rate of 5 bbl/min. Reduce pump rate to 3 bpm prior to latching DP dart into liner
wiper plug. Note plug departure from liner hanger running tool and resume pumping at full
displacement rate. Displacement volume can be re-zeroed at this point
10. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes. Reduce pump rate as required to avoid packoff.
11. Bump the plug. Do not overdisplace by more than 2 bbls.
Lead Slurry Tail Slurry
Density 12.5 lb/gal 15.3 lb/gal
Yield 2.1 ft3/sk 1.24 ft3/sk
Mix Water 12.01 gal/sk 5.58 gal/sk
Displacement: 4-1/2" DP
(1410* .01422) +
(7617-80-1410) * (3.958^2/1029.4) =
113.3 bbls -mgr
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12. Pressure up to 4200 psi to release the running tool (HRD-E) from the liner
13. Bleed pressure to zero to check float equipment.
14. P/U, verify setting tool is released.
15. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple.
Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops
rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome
hydrostatic differential at liner top).
16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up
to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up
rate until the sleeve area is thoroughly cleaned.
17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation,
do not re-tag the liner top, and circulate the well clean.
18. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP.
19. POOH, LDDP.
Backup release from liner running tool:
20. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to
be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that
the tool is in the neutral position. Apply left-hand torque as required to shear screws.
21. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the
setting tool.
22. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed
slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At
this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to
release collet from the profile.
Ensure to report the following on Wellview:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
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x Note if liner is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Note: Send Csg & cmt report + “As-Run” liner tally to sean.mclaughlin@hilcorp.com
17. Wellbore Clean Up & Displacement
1. No 4-1/2” liner cleanout planned. Service coil will cleanout, displace mud, and blow down well with
N2 prior to perforating.
2. Test liner lap to 3000 psi after tail cement has reached 500 psi compressive strength. 10 min operational
assurance test.
3. Make liner top polish mill run per vendor.
18. Run Completion Assembly
1. Run 4-1/2” tubing completion assembly to above the liner top
x Tubing will be 4-1/2” L-80 12.6# EUE
x Baker S-5 SSSV to be placed between 400’ and 450’ MD
x 1 live GLM’s will be run at 1200’
x Tripoint X NIP – just above the seal stem
2. Swap the well over to FIW
x Circulate a hi-vis pill followed by a soap train per Baroid
x Circulate FIW until clean-up is satisfactory.
x Leave FIW in the annulus.
3. Space out and land seal bore in tie back sleeve. RILDs.
4.Test IA to 3000 psi and tubing to 3000 psi. Charted 30 min.
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5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
19. BOP Schematic
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20. Wellhead Schematic
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21. Anticipated Drilling Hazards
Lost Circulation:
Drill depleted reservoir may cause loss circulation events (as seen in the 2021 program on A-03A and
A-01A)
x Maintain sufficient volumes while drill.
x Maintain ability to take on FIW during drilling phase
x If a LC event occurs pumping cement will be the likely remedy
Ensure 500 lbs of medium/coarse fibrous material, 500 lbs SteelSeal (Angular, dual-composition
carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls flowzan as necessary. Optimize
solids control equipment to maintain density and minimize sand content. Maintain programmed mud
specs.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
x Minimize swab and surge pressures
x Minimize back reaming through coals when possible
H2S:
H2S is not present in this hole section.
Anticollision:
No close approaches.
Page 26 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
22. Jack up position
Page 27 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
23. FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface
pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 28 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
24. Choke Manifold Schematic
Page 29 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
Page 30 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
25. Casing Design Information
Page 31 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
26. 8-1/2” Hole Section MASP
Page 32 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
27. Plot (NAD 27) (Governmental Sections)
Page 33 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
28. Slot Diagram
Page 34 PTD August 18, 2025
NCI A-17A
Drilling Program
PTD xxxxxx
29. Directional Program (wp02) - Attached separately
! "
#$$
% #
% # !
1275
1700
2125
2550
2975
3400
3825
4250
4675
5100
5525
5950
6375
6800
7225True Vertical Depth (850 usft/in)-850 -425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100
Vertical Section at 54.33° (850 usft/in)
NCIU A-17A tgt
1000
1500
2
00
0
2
5
0
0
3
0
0
0
NCI A-17
1000
1500
2
00
0
2
5
0
0
3
0
0
0
NCI A-17 PB1
9-5/8" KOP
4-1/2" x 8-1/2"
1000
1500
2000
2 5 0 0
3 0 0 0
3500400045005 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
7 6 1 7
NCIU A-17A wp02
KOP: 12º/100' : 1600' MD, 1542.13'TVD : 150° RT TF
End Dir : 1617' MD, 1556.49' TVD
Start Dir 4º/100' : 1717' MD, 1641.75'TVD
End Dir : 3791.52' MD, 3460.68' TVD
Start Dir 3º/100' : 4191.52' MD, 3712.41'TVD
End Dir : 5091.52' MD, 4419.84' TVD
Total Depth : 7617' MD, 6726.98' TVD
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: NCIU A-17
Water Depth: 101.00
+N/-S +E/-W
Northing Easting Latittude Longitude
0.00 0.00 2586730.75 331992.23 61° 4' 36.3852 N 150° 56' 55.6793 W
SURVEY PROGRAM
Date: 2025-08-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
386.00 1255.00 Gyro-GC_Drill Pipe (NCI A-17 PB1) 3_Gyro-GC_Drill pipe
1276.40 1600.00 MWD+AX+Sag (1) (NCI A-17 PB1) 3_MWD+AX+Sag
1600.00 2000.00 NCIU A-17A wp02 (NCIU A-17A) 3_MWD_Interp Azi+Sag
2000.00 7617.00 NCIU A-17A wp02 (NCIU A-17A) 3_MWD+AX+Sag
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: NCIU A-17 - Slot 1001, True North
Vertical (TVD) Reference:NCI Planned RKB @ 126.63usft
Measured Depth Reference:NCI Planned RKB @ 126.63usft
Calculation Method:Minimum Curvature
Project:North Cook Inlet
Site:North Cook Inlet Unit
Well:Plan: NCIU A-17
Wellbore:NCIU A-17A
Design:NCIU A-17A wp02
CASING DETAILS
TVD TVDSS MD Size Name
1542.97 1416.34 1601.00 9-5/8 9-5/8" KOP
6726.98 6600.35 7617.00 4-1/2 4-1/2" x 8-1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 1600.00 33.25 276.20 1542.13 83.88 -298.98 0.00 0.00 -193.98 KOP: 12º/100' : 1600' MD, 1542.13'TVD : 150° RT TF
2 1617.00 31.50 278.15 1556.49 85.01 -308.01 12.00 150.00 -200.66 End Dir : 1617' MD, 1556.49' TVD
3 1717.00 31.50 278.15 1641.75 92.42 -359.74 0.00 0.00 -238.36 Start Dir 4º/100' : 1717' MD, 1641.75'TVD
4 1917.00 29.63 293.49 1814.21 119.58 -456.97 4.00 110.00 -301.51
5 3791.52 51.00 72.00 3460.68 599.97 -143.16 4.00 147.79 233.54 End Dir : 3791.52' MD, 3460.68' TVD
6 4191.52 51.00 72.00 3712.41 696.03 152.48 0.00 0.00 529.73 Start Dir 3º/100' : 4191.52' MD, 3712.41'TVD
7 5091.52 24.00 72.00 4419.84 863.77 668.74 3.00 180.00 1046.96 End Dir : 5091.52' MD, 4419.84' TVD
8 7617.00 24.00 72.00 6726.98 1181.20 1645.67 0.00 0.00 2025.70 Total Depth : 7617' MD, 6726.98' TVD
-350-17501753505257008751050122514001575175019252100South(-)/North(+) (350 usft/in)-875 -700 -525 -350 -175 0 175 350 525 700 875 1050 1225 1400 1575 1750 1925 2100 2275West(-)/East(+) (350 usft/in)NCIU A-17A tgtKOP71007345250500750100012501500175020002250NCI A-17250500750100012501500175020002250NCI A-17 PB19-5/8" KOP4-1/2" x 8-1/2"250500750100012501500175020002250250027503 0 0 0
3 2 5 0
3 5 0 0
3 7 5 0
4 0 0 0
4 2 5 0
4 5 0 0
4 7 5 0
5 0 0 0
5 2 5 0
5 5 0 0
5 7 5 0
6 0 0 0
6 2 5 0
6 5 0 0
6 7 2 7 NCIU A-17A wp02KOP: 12º/100' : 1600' MD, 1542.13'TVD : 150° RT TFEnd Dir : 1617' MD, 1556.49' TVDStart Dir 4º/100' : 1717' MD, 1641.75'TVDEnd Dir : 3791.52' MD, 3460.68' TVDStart Dir 3º/100' : 4191.52' MD, 3712.41'TVDEnd Dir : 5091.52' MD, 4419.84' TVDTotal Depth : 7617' MD, 6726.98' TVDCASING DETAILSTVDTVDSS MDSize Name1542.97 1416.34 1601.00 9-5/8 9-5/8" KOP6726.98 6600.35 7617.00 4-1/2 4-1/2" x 8-1/2"Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-17Wellbore: NCIU A-17APlan: NCIU A-17A wp02WELL DETAILS: Plan: NCIU A-17Water Depth: 101.00+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.00 2586730.75331992.2361° 4' 36.3852 N 150° 56' 55.6793 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-17 - Slot 1001, True NorthVertical (TVD) Reference:NCI Planned RKB @ 126.63usftMeasured Depth Reference:NCI Planned RKB @ 126.63usftCalculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200Measured Depth (600 usft/in)A-08NCI A-17NCIU A-13NCIU A-09PB1NCIU A-16No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: NCIU A-17 NAD 1927 (NADCON CONUS)Alaska Zone 04Water Depth: 101.00+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.002586730.75331992.23 61° 4' 36.3852 N 150° 56' 55.6793 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NCIU A-17 - Slot 1001, True NorthVertical (TVD) Reference:NCI Planned RKB @ 126.63usftMeasured Depth Reference:NCI Planned RKB @ 126.63usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool386.00 1255.00 Gyro-GC_Drill Pipe (NCI A-17 PB1) 3_Gyro-GC_Drill pipe1276.40 1600.00 MWD+AX+Sag (1) (NCI A-17 PB1) 3_MWD+AX+Sag1600.00 2000.00 NCIU A-17A wp02 (NCIU A-17A) 3_MWD_Interp Azi+Sag2000.00 7617.00 NCIU A-17A wp02 (NCIU A-17A) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700 6000 6300 6600 6900 7200Measured Depth (600 usft/in)A-08NCI A-17NCIU A-13NCIU A-16NO GLOBAL FILTER: Using user defined selection & filtering criteria1600.00 To 7617.00Project: North Cook InletSite: North Cook Inlet UnitWell: Plan: NCIU A-17Wellbore: NCIU A-17APlan: NCIU A-17A wp02CASING DETAILSTVD TVDSS MD Size Name1542.97 1416.34 1601.00 9-5/8 9-5/8" KOP6726.98 6600.35 7617.00 4-1/2 4-1/2" x 8-1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
NCIU A-17A
TERTIARY GAS
225-089
NORTH COOK INLET
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:N COOK INLET UNIT A-17AInitial Class/TypeDEV / PENDGeoArea820Unit11450On/Off ShoreOffProgramDEVWell bore segAnnular DisposalPTD#:2250890Field & Pool:NORTH COOK INLET, TERTIARY GAS - 564570NA1 Permit fee attachedYes ADL175892 Lease number appropriateYes3 Unique well name and numberYes NORTH COOK INLET, TERTIARY GAS - 564570 - governed by CO 68A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 30" driven to 384'18 Conductor string providedYes This well will sidetrack from existing 9-5/8" surface casing at 1600' MD19 Surface casing protects all known USDWsYes Surface casing and 4-1/2" production liner to be fully cemented.20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Spartan 151 jackup has adequate tankage and good trucking support24 Adequate tankage or reserve pitYes Approved sundry 325-49025 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches with HSE risk.26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure28 Drilling fluid program schematic & equip list adequateYes 5M 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo H2S is unlikely. Monitoring will be required.33 Is presence of H2S gas probableNA This well is a gas producer.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not expected in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes see comments below36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate9/8/2025ApprMGRDate9/10/2025ApprADDDate9/8/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateSterling slightly under-pressured (~ 8.1 ppg EMW). Beluga A to I normally pressured (~ 8.3 ppg). Beluga M to S over pressured (~9-9.8 ppg)JLC 9/10/2025
