Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/16/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240116
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet #
BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL
BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF
BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF
BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF
BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF
GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL
GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL
GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf
GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL
IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug
IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination
KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf
MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord
MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech
MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF
MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf
MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf
MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf
PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF
PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT
PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT
PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP
PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT
PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF
PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT
PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF
PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT
TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf
T39958
T39959
T39960
T39961
T39962
T39963
T39964
T39964
T39965
T39966
T39966
T39967
T39968
T39969
T39970
T39970
T39971
T39971
T39972
T39973
T39974
T39975
T39976
T39977
T39978
T39979
T39980
T39981
BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.01.16 13:56:40 -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: 12/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241205
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet
AN 15(GRANITE PT
ST 18742 15) 50733200700000 167082 11/18/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 10/24/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf
BRU 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 11/12/2024 AK E-LINE Plug/Perf
END 2-72 50029237810000 224016 10/16/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 10/18/2024 HALLIBURTON COILFLAG
MGS-ST 17595-05 50733100710000 165038 10/6/2024 AK E-LINE CBL
MPU F-109 50029235960000 218014 10/28/2024 READ CaliperSurvey
MPU J-02 50029220710000 190096 11/16/2024 READ CaliperSurvey
MPU J-47 50029238010000 224120 11/9/2024 READ LeakPointSurvey
MPU D-01 50029206640000 181144 10/23/2024 AK E-LINE TubingPunch
MPU F-02 50029226730000 196070 11/18/2024 READ CaliperSurvey
MPU I-08 50029228210000 197192 10/22/2024 AK E-LINE TubingPunch
MPU I-08 50029228210000 197192 10/26/2024 HALLIBURTON JETCUT
MPU L-60 50029236780000 220048 10/26/2024 HALLIBURTON MFC24
MRU M-25 50733203910000 187086 11/15/2024 AK E-LINE Plug
NCIU A-21 50883201990000 224086 11/9/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/19/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Perf
NCIU A-21 50883201990000 224086 10/30/2024 AK E-LINE Plug/Perf
PBU 06-07A 50029202990100 224043 9/30/2024 HALLIBURTON RBT
PBU 14-41A 50029222900100 224076 11/8/2024 HALLIBURTON RBT
PBU H-36A 50029226050100 200025 10/26/2024 HALLIBURTON RBT
PCU 02A 50283200220100 224110 11/24/2024 AK E-LINE Perf
Please include current contact information if different from above.
T39808
T39809
T39810
T39810
T39811
T39812
T39813
T39813
T39814
T39815
T39816
T39817
T39818
T39819
T39820
T39820
T39821
T39822
T39823
T39823
T39823
T39823
T39824
T39825
T39826
T39827
BRU 233-23T 50283202000000 224088 10/21/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/30/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.05 14:52:46 -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): Beluga River Field
GL: 75.3' 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 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" L-80 120'
7-5/8" L-80 2,730'
3-1/2" L-80 6,221'
3-1/2" L-80 2,607'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
00532 80
11/1/2024 24
Flow Tubing
0
3136
N/A31360
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9.2#
2,788'
2,575'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
10/22/2024
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
321665
321809
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
Conductor
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2631695
2631795
TOP HOLE SIZE
CBL 9-14-24, LWD+PB1 (DGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs
N/A
N/A
N/A
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
320560 2630904
50-283-20200-00-00July 30, 2024
N/A
BRU 233-23TAugust 14, 2024504' FSL, 2546' FWL, Sec 23, T13N, R10W, SM, AK
93.8'
Sterling - Beluga Gas Pool
ADL 21127, ADL 17658, ADL 21128
6,500' MD / 6,223' TVD
6,433' MD / 6,156' TVD
1318' FSL, 1643' FEL, Sec 23, T13N, R10W, SM, AK
CASING, LINER AND CEMENTING RECORD
1421' FSL, 1501' FEL, Sec 23, T13N, R10W, SM, AK
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
10/14/2024 224-088 / 324-466 / 324-507
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,
Tieback Assy.Tieback
TUBING RECORD
L - 415 sx / T - 122 sx6-3/4"
9-7/8"
Driven
Surface L - 409 sx / T - 174 sx
SETTING DEPTH TVD
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Surface
2,926'
9.3#
Surface
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,753' 6,498'
Surface
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
Received by James
Brooks on 11/6/2024 at
3:06pm
Complete
10/14/2024
JSB
RBDMS JSB 111224
GDSR-11/22/24BJM 1/24/25
SFD 3/27/2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel F4 4635' 4367'
3149' 2931'
3952' 3687'
4008' 3743'
4229' 3962'
4560' 4292'
5039' 4769'
5362' 5091'
6054' 5779'
6426' 6150'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Bel I9
Bel E
ST X1
Bel F
Bel I
ST C5
Bel D
Bel G
Bel H
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
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: 2024.11.06 11:52:59 -
09'00'
Sean
McLaughlin
(4311)
Updated by CJD 11-06-24
Schematic
Beluga River Unit
BRU 233-23T
PTD: 224-088
API: 50-283-20200-00-00
PBTD = 6,433’ / TVD = 6,156’
TD = 6,500’ / TVD = 6,223’
RKB = 19.85’
PB1
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01”Surf 120’
7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,926’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,753’6,498’
TUBING DETAIL
3-1/2"Prod Tieback 9.3 L-80 EUE 8RD 2.992”Surf 2,788’
3/ 4***
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 20’2.992”11”Cactus CTF-ONE-CTL Hanger w/ 4” Type H BPV profile
2 2,717’2.992”6.510”DHL Retrievable packer, pinned @ 36K release
3 2,753’4.875”6.540”Ranger Liner hanger w/ Scout packer
4 2,788’2.930”4.630”Seal Stem (1’ off no-go 10ft overall length)
5 5,796’N/A N/A 3.5” CIBP (set 10/15/24)
OPEN HOLE / CEMENT DETAIL
7-5/8"170 bbls of 12 ppg lead followed by 42 bbls of 15.8 ppg tail, w/39 bbls of returns to
surface 8/2/24.
PB1
Original PB1 hole drilled to 7106 with 3-1/2” casing run to 7106 and cemented, but when
trying to release from liner hanger, tubing parted at 3319’. Spotted a 22bbl 15.8 ppg
cement plug @ 3316’. Drilled through cement plug at 2966’ for new hole.
3-1/2”177 bbls of 12 ppg lead followed by 27 bbls of 15.3 ppg tail in 6.75” hole. 53 bbls of
Cement returned 8/17/24. TOC based on CBL run on 9/14/24 2,925’ MD.
6-3/4”
hole
2
1
PERFORATION DETAIL
Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments
Pool Top Sterling A1 - 3,441’ MD / 3,202’ TVD
Beluga F4 4,635'4,641'4,367'4,373'6'10/31/24 Open
Beluga F4 4,673'4,681'4,404'4,412'8'10/31/24 Open
Beluga F4 4,695'4,699'4,426'4,430'4'10/31/24 Open
Beluga F5 4,715'4,719'4,446'4,450'4'10/31/24 Open
Beluga F6 4,792'4,796'4,523'4,527'4'10/31/24 Open
Beluga F6 4,801'4,806'4,532'4,537'5'10/30/24 Open
Beluga F10 4,981'4,984'4,711'4,714'3'10/30/24 Open
Beluga F10 4,986'4,993'4,716'4,723'7'10/30/24 Open
Beluga F10 5,024'5,027'4,754'4,757'3'10/30/24 Open
Beluga F10 5,029'5,038'4,759'4,768'9'10/23/24 Open
Beluga G 5,067'5,087'4,797'4,818'20'10/23/24 Open
Beluga G2 5,109'5,117'4,839'4,847'8'10/23/24 Open
Beluga G2 5,136'5,141'4,866'4,870'5'10/23/24 Open
Beluga G2 5,149'5,153'4,879'4,883'4'10/22/24 Open
Beluga G4 5,184'5,191'4,914'4,921'7'10/22/24 Open
Beluga G5 5,201'5,204'4,931'4,935'3'10/22/24 Open
Beluga H 5,376'5,379'5,105'5,108'3'10/22/24 Open
Beluga H1 5,444'5,449'5,173'5,178'5'10/22/24 Open
Beluga H2 5,459’5,471’5,187’5,199’12 10/22/24 Open
Beluga H3 5,486'5,493'5,214'5,221'7'10/22/24 Open
Beluga H3 5,502'5,512'5,230'5,240'10'10/21/24 Open
Beluga H4 5,525’5,531’5,253’5,259’6’10/20/24 Open
Beluga H8 5,644'5,653'5,372'5,381'9'10/19/24 Open
Beluga H9 5,682'5,690'5,409'5,417'9'10/18/24 Open
Beluga H11 5,806'5,810'5,533'5,537'4'10/14/24 Plugged
Beluga I7 6,334'6,353'6,058'6,077'19'10/14/24 Plugged
RA 5,698’
RA 4,122’
NOTES
A second packer was run due to the first packer leaking, August 2024
***GR/JB & plug setting tool will stick in gap at liner top packer, or small tool
string because of mule shoe on low side of pipe. See wellfile pics for details
Short Joints (~15ft)4,122’ (RA Tag) , 4666’, 5120’, 5698 (RA Tag)
Page 1/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:7/28/2024 End Date:8/20/2024
Report Number
1
Report Start Date
7/28/2024
Report End Date
7/29/2024
Operation
PU and stored HandyBerm, brought in crane, removed catwalk, set crane and lowered doghouse, removed iron roughneck from floor, removed all three pit modules and
jig, removed compressor skid and pump 2. Removed 40' connex, loaded exposed rig mats, transported all to J pad and staged, started laying available rig mats.
Removed HPU skid and pump 1, cont setting rig mats at J pad, removed gen skid and doghouse, transported to J pad. Brought in 2n d crane, staged and picked derrick
off carrier, carrier off sub, sub off pony walls. Loaded all and transported to J pad, having to set sub on road and pull under overhead power lines at G pad access road.
On J pad swapped grating on cellar box, set two service shacks on Drillers side, set pony walls and test pump, staged cranes and set sub on pony walls and centered
over conductor.
Set carrier on sub, and install dill line spool on drawworks. Set and pin derrick. Spot doghouse and position crane to safety s pot doghouse while rainsing. Spot TD HPU,
combo building, mud tank #1, jig, MP #1, mud tank #2 and #3, 40' c-can and boiler house. Lower walk way between pumps. Lower landings and walkways on mud tanks.
Raise pit roofs and degasser. Spot in and set upright water tank. R/U power cables, air, water and diesel lines. R/U lighting a nd power up gens.
Perform pre-raise derrick inspection. Raise and pin derrick. Install remaining rif floor plates and handrails. Lower drill line, service loop and kelly hose from derrick. Lower
and pin monkey board and wind walls. R/U remaining utility lines around rig.
Report Number
2
Report Start Date
7/29/2024
Report End Date
7/30/2024
Operation
Set upright water tank, set felt/liner for catwalk then set catwalk. RD trailers on H and G pads, staged lower torque tube in V door, spotted crane, set trip tank pump,
centrifuge and poorboy degasser. Set rig mats for office trailers, set safety shack and DSM trailer. Set change shack w/gen set, spooled up drill line, held PJSM and
scoped up derrick.
Set sleeper trailer and pushers shack and powered up. Installed turnbuckles and T bar on lower torque tube, staged torque bushi ng on rig floor, PU topdrive and
transfered to blocks. Installed kelly hose and service loop. Function tested topdrive.
R/U snub lines on tongs. Mobilize pipe handling equipment and XO subs to rig floor. N/U diverter T, annular, bell nipple, knife valve and vent line. Build 150bbl of spud
mud. Changed oil filters on camp hen . Plugged in 3rd party shacks.
Finish R/U diverter vent liner. Install 4" ball valves on the condutor outlets. Installs and T-hoses on bag and knife valve and pressure up Koomey. Work on second 150 bbl
batch of spud mud. Install gas alarms in cellar, rig floor and mud pits. Function test knife valve. Knife valve opened 22 seconds / Bag closed 36 seconds. Cont. working on
rig acceptance checklist.
Report Number
3
Report Start Date
7/30/2024
Report End Date
7/31/2024
Operation
Cont working rig acceptance checklist, cont building spud mud, staged well on diverter signs, laid out DP for racking, set ceme nt silo, Quadco Rep calibrated and certified
assorted pressure gauges, Jim Regg waived witness of diverter test at 09:06 on 7-30-24, did walk through rig tour with Hilcorp Environmental Specialist Stetson Sannes
and two AOGCC Reps (permitting dept), rig Electrician tested all audio/visual gas alarms and sensors.
Racked and tallied DP for PU, finished rig acceptance checklist, transfered good 6% KCL mud from tank farm to pre-mix pits, Accepted rig at 14:00 on 7-30-24.
After discussion with rig Supervisors on drill line anomaly, slipped and cut 425' of drill line to capture cable samples to be sent in for inspection.
Performed diverter function test w/jnt 4 1/2" DP, performed koomey draw down, measured vent line and nearest ignition source, function flow show, gain/loss and PVT
alarms.
Set mousehole in rotary table, PU racked back 48 stands DP, 8 stands HWDP and jar stand.
MU BHA #1 as per DD/MWD.
Fill conductor and surface diverter with spud mud, flow/leak checking the surface equip. No leaks. Tagged bottom of the the conductor hole @ 134'.
Drill ahead F/134' T/401'
P/U-25K S/O-22K ROT-23K
GPM-350 SPP-750 psi RPM-45 TQ-2.2K WOB-0/3.2K MW-8.8 ppg max gas-2 units.
Report Number
4
Report Start Date
7/31/2024
Report End Date
8/1/2024
Operation
CBU at 401', at 356 gpm-767 psi, 40 rpm-3100 ft/lbs off bott torque.
Pulled up hole from 401' to 346', PU jars and single HWDP, eased back to bottom.
Cont drilling 9 7/8" hole from 401' to 814'. Rot wob 1-2K, 355 gpm-756 psi, 40 rpm-2000 ft/lbs on bott torque, 120 ft/hr ROP. S liding wob 1-12K, 352 gpm-774 psi, 149 psi
diff, 290 ft/hr ROP.
MW 8.8+/vis 284, ECD 9.4 ppg, BGG 3 units.
Cont drilling from 814' to 1259'. Sliding wob 3-10K, 400 gpm-1100 psi, 126 psi diff, 200 ft/hr ROP. Rot wob 2-3K, 400 gpm-1068 psi, 45 rpm-3016 ft/lbs on bott torque, 120
ft/hr ROP.
MW 8.8+/vis 217, ECD 9.5 ppg, BGG 3 units
Cont drilling from 1259' to 1462'. Sliding wob 3-10K, 400 gpm-1100 psi, 126 psi diff, 200 ft/hr ROP. Rot wob 2-3K, 400 gpm-1068 psi, 45 rpm-3016 ft/lbs on bottom torque,
120 ft/hr ROP.
MW 8.8+/vis 217, ECD 9.5 ppg, BGG 3 units
Distance to well plan 3.29’, low 2.42’, right 2.23’.
CBU X2
10 min flow check
Short trip F/1462' T/409' with no issues.
PUW=42K SOW=29K
Rig service
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147Permit to Drill (PTD) #:224-088
Wellbore API/UWI:50-283-20200-01-0000
Page 2/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
RIH F/409' T/1462' with no issues and no fill on bottom.
CBU and pump high vis sweep to clean hole. Sweep came back on time and with 60% increase in returns.
Cont drilling from 1462' to 1875'. Sliding wob 3-10K, 400 gpm-1100 psi, 50psi diff, 200 ft/hr ROP. Rot wob 2-5K, 400 gpm-1290 psi, 50 rpm-3.2K-5K ft/lbs on bottom
torque, 120 ft/hr ROP.
MW 8.8+/vis 196, ECD 9.5 ppg, BGG 3 units
Distance from plan 10.16', low 9.61', right 3.32'
Report Number
5
Report Start Date
8/1/2024
Report End Date
8/2/2024
Operation
Cont drilling from 1875' to 2401'. Rot wob 1-6K, 400 gpm-1343 psi, 40 to 50 rpm-5400 to 6600 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 11K, 410 gpm-1435 psi, 58
psi diff, 218 ft/hr ROP.
MW 8.8+/vis 176, ECD 9.4 to 9.6 ppg, BGG 3 units.
Gave AOGCC 48 hr notice for initial BOP test. Crew held diverter drill.
Cont drilling from 2401' to 2770'. Rot wob 4 to 10K, 400 gpm-1362 psi, 45 rpm-6400 ft/lbs on bott torque, 50 to 120 ft/hr ROP. Sliding wob 3K, 400 gpm-1280 psi, 90 psi
diff, 140 ft/hr ROP.
MW 8.8+/vis 149, ECD 9.6 ppg, BGG 3 units.
Cont drilling from 2770' to 2933'. Rot wob 4 to 10K, 400 gpm-1362 psi, 45 rpm-6400 ft/lbs on bott torque, 50 to 120 ft/hr ROP. Sliding wob 8K, 400 gpm-1400psi, 200 psi
diff, 60 ft/hr ROP.
MW 8.8+/vis 149, ECD 9.6 ppg, BGG 5 units.
PUW=65K SOW=37K ROT=46K
CBU X2
Obtain final survey
10 min flow check
POOH F/2933' T/409' with no issues
Rig service
Static loss rate 1bph
RIH F/409' T/2900' with no issues.
Wash last stand to BTM with no fill on BTM.
Circ nut plug condet sweep around 30% increase in cuttings
Flow check well for 10 mins
POOH F/2933' T/2200'
PUW=65K SOW=40K
Report Number
6
Report Start Date
8/2/2024
Report End Date
8/3/2024
Operation
Cont POOH from 2200' to HWDP at 716'.
Racked back HWDP, LD jars and NM DC's, plugged in and downloaded MWD data, LD smart tools, drained and flushed motor, bit grade d 1-1 in gauge.
Cleaned and cleared rig floor, drained stack, C/O valves on topdrive, dummy ran hanger and marked landing joint.
RU casing equipment and fill up hose, staged centralizers, held PJSM, staged casing (on trailer)
PU and BakerLok'd shoe track, topped off and checked floats (ok), cont PU single in hole with 35 jnts 7 5/8” 29.7# L-80 DWC/C casing to 1446', filling on the fly, topping
off every 10 jnts. Displacement 6 bbls under at this depth. Up wt 38K, dwn wt 29K. MU circ swedge and topdrive.
CBU staging up to 5 bpm-65 psi, lost 1.5 bbls during circ. Shut down and broke off topdrive and circ swedge.
Cont PU single in hole another 35 jnts from 1446' to 2901', MU hanger/landing joint, S/O and landed hanger with shoe at 2925.66 '. Up wt 70K, dwn wt 39K.
MU circ swedge and topdrive on stump, stage circ rate up to 216 gpm-115 psi, installed bail extensions, RD casing tongs and rem oved from rig floor, staged plug
launcher, called out cementers and got them staged.
MU plug launcher and hardline, Halliburton loaded lines with 10 bbls water and checked for leaks. Halliburton pressure tested l ines at 650 psi low 4620 psi high, good
tests. Halliburton pumped 73 bbls 10.5 ppg Tuned Spacer at 4 bpm-150 psi, dropped bottom plug and pumped 170 bbls (409 sx) 12 ppg Type I II lead cement at 3 to 4
bpm-100 to 150 psi, followed by 42 bbls (174 sx) 15.8 ppg Type I II tail cement at 5 bpm-404 psi. Halliburton dropped top plug then displaced with 8.9 ppg Spud Mud at 4
to 4.8 bpm 220 to 680 psi. Saw green cement at surface 84 bbls into displacement. Slowed pump to 3 bpm with 20 bbl to go. Did bump the plug 129 bbls into
displacement (calculated 130 bbls). Held 1460 psi (FCP of 680 psi) for 3 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 73 bbls of Spacer returns to
surface and 39 bbls lead cement to surface. Mix water temp 53 deg. Pumped 75% excess on lead and 50% on tail. Lost 21 bbls throughout the job. Did reciprocate casing
until pumping 20bbls of lead. Up wt 65K, dwn wt 40K. CIP at 00:55 hrs, 8/3/2024. RD and released Halliburton.
Back out and LD LJ.
Flush stack with black water pill.
Johnny whack the stack with black water pill while functioning the annular.
ND surface stack and diverter line.
Install and orientate wellhead assy. as per wellhead rep.
Report Number
7
Report Start Date
8/3/2024
Report End Date
8/4/2024
Operation
Wellhead Rep tested neck seals at 5000 psi for 10 minutes, good test, RD and released wellhead rep.
Set spacer spool and BOP stack. Installed kill and choke lines, installed flow riser and flow line, installed 4 way chains. Cleaned up cellar and rig floor.
Set test plug with 4 1/2" test joint, opened annulus valve, flooded surface lines and equipment, functioned rams and purged air in choke manifold. Shell tested stack to
choke manifold at 250/3000 psi. AOGCC Rep on location at 14:00 hrs.
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 3/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Rig electrician tested audio/visual gas alarms and sensors. Tested all BOPE at 250 low, 3000 high for 5 min each. Tested with both 4 1/2" and 3 1/2" test joints. Had one
F/P on choke HCR low test.
Racked and tallied 50 jnts 4 1/2" DP.
Pulled test plug, set wear ring, RU on kill line, purged air, closed blinds, pumped 70 gallons and achieved 3669 psi on surface casing. Held 30 minutes on chart, good test,
bled back 70 gallons, RD test equipment.
PU and rack back 50 jts of 4.5'' DP
Clean and clear rig floor.
Prep for PU BHA.
MU BHA#2 as per DD / MWD.
Report Number
8
Report Start Date
8/4/2024
Report End Date
8/5/2024
Operation
Plugged in and uploaded MWD data, MU topdrive and shallow pulse tested, held PJSM and loaded sources, cont RIH with HWDP and jars to 678'.
Cont PU single in hole 60 jnts DP from 678' to 2528'. RIH on stands from 2528' to 2806' and started taking weight. MU topdrive, filled pipe, washed and reamed down to
2841' at 206 gpm-1028 psi, 30 rpm-3900 ft/lbs torque. Tagged top wiper plug at 2841'.
Drilled FE and shoe track to 2925', rathole cement to 2933', 20' new formation to 2953'. 204 gpm-1218 psi, 30 rpm-4300 ft/lbs on bott torque.
CBU, racked back stand, shut down and cleaned up under shakers and trough. Pumped 25 bbl hi-vis spacer follwed with 8.9 ppg 6% KCL and displaced well,
overboarding returns until good mud to surface. 200 gpm-1101 psi, 20 rpm-4300 ft/lbs torque. CBU twice and racked back another stand to put bit inside casing.
Installed headpin on stump, RU test equipment to DP and kill line, purged air, closed upper rams. Pumped 18.75 gallons to achieve 795 psi on formation and held 10
minutes. Bled down to 686 psi then bled back 16.5 gallons. Sent data to Drilling Engineer, called LOT at 676 psi for a 13.66 ppg EMW.
RD test equipment, blew down surface lines and choke manifold, broke off headpin. Eased in hole 2 stands to 2953'.
Resumed drilling 6 3/4" hole from 2953' to 3072', rot wob 1-2K, 249 gpm-1220 psi, 40 to 50 rpm-5000 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2-3K, 249
gpm-1339 psi, 143 psi diff, 130 ft/hr ROP.
MW 8.8+/vis 56, ECD 9.6 ppg, BGG 2 units.
Drilling 6 3/4" hole from 3072' to 3492', rot wob 1-2K, 249 gpm-1270 psi, 40 to 50 rpm-5500 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2-3K, 249 gpm-1339 psi, 153
psi diff, 120 ft/hr ROP. PUW=55K SOW=37K ROT=44K
MW 8.8+/vis 56, ECD 9.8 ppg, BGG 10units MAX gas 137units.
Drilling 6 3/4" hole from 3492' to 3879', rot wob 1-2K, 249 gpm-1270 psi, 40 to 50 rpm-5500 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2-3K, 249 gpm-1339 psi, 120
psi diff, 120 ft/hr ROP. PUW=63K SOW=40K ROT=48K
MW 8.8+/vis 56, ECD 9.8 ppg, BGG 50units MAX gas 108units.
Report Number
9
Report Start Date
8/5/2024
Report End Date
8/6/2024
Operation
Drilled from 3879' to 3942'. Rot wob 1-2K, 241 gpm-1226 psi, 50 rpm-5800 ft/lbs on bott torque, 120 ft/hr ROP.
CBU twice at 240 gpm-1144 psi, 50 rpm-5600 ft/lbs off bott torque. Obtained on bottom survey and SPR's, flow check showed slight seepage.
Pulled up hole on elevators from 3942', up wt 68K. Parked at 2880' inside casing, no issue tripping. Calc hole fill = 6.9 bbls, actual hole fill = 7.7 bbls.
Serviced rig and topdrive, checked seal leak on top drive, drained some oil out of gear box. Loss rate at .64 bph on trip tank.
TIH from 2933' to 3882', dwn wt 38K. MU topdrive and filled pipe, washed to bottom and started sweep around.
Pumped a 25 bbl hi-vis nutplug condet sweep around at 220 gpm-1086 psi, 47 rpm-5000 ft/lbs off bott torque. Sweep was back on time and had 100% increase in
cuttings.
Cont drilling 6 3/4" hole from 3942' to 4247'. Rot wob 1-2K, 175 gpm-870 psi, 50 rpm-6442 ft/lbs on bott torque, 60 ft/hr. Slid ing wob 4K, 175 gpm-890 psi, 144 psi diff, 90
ft/hr ROP. MW 8.9+/vis 51, ECD 9.7 ppg, BGG 30 units, max gas 243 units.
Reduced our gpm and ROP at 3700' tvd as we are drilling into the Beluga D and E formations.
Between 4068' and 4109' md hole took 7 bbl drink then seemed to heal up.
Control drilling 6 3/4" hole from 4247' to 4459'. Rot wob 1-2K, 175 gpm-1030 psi, 50 rpm-6750 ft/lbs on bott torque, 60 ft/hr. MW 8.9+/vis 51, ECD 9.7 ppg, BGG 30 units,
max gas 120 units.
Reduced our gpm and ROP at 3700' tvd as we are drilling into the Beluga D and E formations.
Control drilling 6 3/4" hole from 4459' to 4740'. Rot wob 1-2K, 175 gpm-1030 psi, 50 rpm-6742 ft/lbs on bott torque, 60 ft/hr. MW 8.9+/vis 51, ECD 9.8 ppg, BGG 30 units,
max gas 200units.
Reduced our gpm and ROP at 3700' tvd as we are drilling into the Beluga D and E formations.
Report Number
10
Report Start Date
8/6/2024
Report End Date
8/7/2024
Operation
Continue Drilling 6 3/4'' Hole section f/ 4740' t/ 5131' 200 gpm 1250 psi 50 rpm 7.8k tq on bottom, MW 8.95 ppg ECD 9.8 ppg, ROP 65-95, WOB 3-5k, 74k PUW 48k
SOW 58k ROT , Max gas 206 units.
CBU, obtain survey and SPR's flow check well static.
Make wiper trip f/ 5131' t/ 4136' with no issues.
Service rig, grease top drive and blocks, inspect draw works brake linkage and Eaton brake, Static loss rate 1 BPH
RIH f/ 4136' t/ 5131' wash last stand to bottom, No Issues Pump Hi Vis Sweep around, sweep back 100 stks early 100% increase in cuttings.
Continue Drilling 6 3/4'' Hole section f/ 5131' t/ 5219' 225 gpm 1350 psi 50 rpm 8k tq on bottom, 2-5k WOB, PUW 78k SOW 52k ROT 60k
Cont. directional drilling 6-3/4" production hole F/5219'-T/5568'. P/U-117K S/O-69K ROT-86K GPM-225 SPP-1435 psi RPM-50 WOB-3K TQ-8.1K Diff-200 psi ROP-90
Flow-19% MW-9.0 ppg ECD-10.02 ppg Max gas- 396 units.
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 4/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/5568. Pumped 25 bbls Hi-Vis sweep @ 5630', sweep came back 9 bbls early with a 40%
increase in cuttings. Obtained new set of SPR's. Current depth at report time- 5872'. P/U-120K S/O-70K ROT-87K GPM-223 SPP-1480 psi RPM-50 WOB-5/7K TQ-8.7K
Diff-150 psi ROP-90 Flow-19% MW-9.05 ppg ECD-10.2 ppg Max gas- 138 units. Distance to well plan: 7.19' 5.18' High 4.99' Left.
Report Number
11
Report Start Date
8/7/2024
Report End Date
8/8/2024
Operation
Continue Drilling 6 3/4'' Hole Section f/ 5872' t/ 6126' 225 gpm 1500 psi 50 rpm 8.5k tq on bottom, Max Gas 394 unit 2-4k WOB, 125k PUW 70k SOW 90k ROT, 9.0 ppg
MW ECD 10.3 ppg
Circulate bottoms up, Obtain survey and SPR's Flow check well slight static loss dropped 4'' in riser in 10 min
POOH f/ 6128' t/ 2875' with out issues
Service rig and top drive, grease blocks and inspect draw works, change oil in draw works motor, and camp gen, clean suction screens.
RIH f/ 2875' t/ 6086' without issues, Fill Pipe and wash down
Washed down to bottom F/6086' to bottom. Pumped 25 bbl Hi-Vis sweep. Hole unloaded during BU with a max gas of 1316 uint. Sweep came back on time with a 100%
increase in cuttings. GPM-221 SPP-1320 psi RPM-70 TQ-9.2K MW-9.05 ppg ECD-10.1 ppg Max gas- 1316 units.
Resumed directional drilling 6-3/4" production hole as per wp03 F/6126'-T/6391'. P/U-122K S/O-76K ROT-94K GPM-220 SPP-1490 psi RPM-50 WOB-4K TQ-10K
Diff-190 psi ROP-90 Flow-19% MW-9.05 ppg ECD-10.08 ppg Max gas- 751 units.
Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/6391. Pumped 25 bbls Hi-Vis sweep @ 6631', sweep came back on time with a 60% increase
in cuttings. Obtained new set of SPR's. Current depth at report time- 6736'. P/U-122K S/O-77K ROT-95K GPM-226 SPP-1620 psi RPM-50 WOB-5.5K TQ-10.5K Diff-230
psi ROP-90 Flow-19% MW-9.1 ppg ECD-10.1 ppg Max gas- 180 units. Distance to well plan: 3.2' 2.95' High 1.24' Right.
Report Number
12
Report Start Date
8/8/2024
Report End Date
8/9/2024
Operation
Continue Drilling 6 3/4'' Hole Section f/ 6736' t/ 7106' TD 225 gpm 1740 psi 50 rpm 11.2k tq on bottom, MW 9.2 ppg ECD 10.38 ppg, 196 max Gas, 3-6k WOB, 138k PUW
80k SOW 99k ROT. Distance to well plan: 9.51' 8.14' High 4.91' Right
Circulate bottoms up, Obtain survey and SPR's, Flow check well static
POOH on elevators f/ 7106' t/ 6066' without issues
Service rig, grease top drive and blocks, greaase crown and inspect draw works
RIH f/ 6066' t/ 7106' without issues wash last stand to bottom
Circulate sweep out of the hole, sweep back on time 30% increase in cuttings
POOH on elevators f/ 7106' t/ 678' without issues.
Racked back HWDP, L/D jar std. Held PJSM, removed sources. Pugged in and down loaded MWD data. L/D remainder of MWD tools, miked mud motor, B/O bit. Bit
graded 1-1 in gauge.
Cleaned & cleared rig floor. R/U TRS handling equip. loaded catwalk racks with 3.5" tubulars. R/U fill up line. Held PJSM.
M/U shoe track, tested floats (ok). Cont. running 3.5" 9.2# L-80 Wedge 563 liner as per tally. Filling on the fly and topping off every 10 jts. Current depth of 1578'.
Report Number
13
Report Start Date
8/9/2024
Report End Date
8/10/2024
Operation
Continue RIH f/ 1578' t/ 4336' M/U Liner Hanger and cross over to DP RIH t/ 4444'
Circulate bottoms up Max Gas Observed 2225'
RIH w/ 3.5'' Liner on 4.5'' DP f/ 4444' t/ 6935' setting down 10k unable to work down, kelly up and wash to bottom @ 7106'
Circulate bottoms up stage rate t/ 4.5 bpm 700 psi
Spot in cementers P/U and M/U cement head.
Fill lines, P/T lines t/ 500 psi low 4360 psi High, pump 30 bbls 10.5 ppg spacer @ 3 bpm, pump 169 bbls 12 ppg Lead @ 4.5 bpm, pump 24 bbls 15.3 ppg Tail Cement @
3 bpm, drop plug displacve with 74.9 bbls mud, pressure up and check floats, bled back .5 bbls
Attempt to set hanger, pressure up to 2500 psi to set hanger pressure bleeding off unable to set hanger, worked string not able to build pressure to set hanger, left hand
off hanger and release, attempt to get dogs out and set hanger packer unable to see dogs, work string with rotation multiple times, decision made to pull out of liner
hanger with running tools and circulate cement out
Circulate bottoms up x 3 420 gpm 10 bpm 1000 psi 30 bbls spacer and 85 bbls of contaminated mud and cement to surface highest weight seen 11.7 ppg.
R/D circulating equiment L/D cement head, clear floor.
POOH F/2683'-T/Surface. Had 6K of extra weight on the hook. P/U and had Yellow Jacket running tool, hanger, XO, and 3.5" liner jt. on the hook. Called town and
discussed options with engineer.
R/U TRS handling equip. L/D Yellow Jacket hanger, XO, 17 jts. of 3.5" liner and 1 marker pup (583.05'). Estimated TOF @ 3,316.92'.
R/D TRS handling equip. P/U flushing tool, flushed BOP stack cavities with black water and L/D same. Stagged cleanout BHA on ca twalk.
P/U & M/U 6-3/4" dumb iron cleanout BHA #3.
RIH with BHA #3, F/587' to current depth of 2280'.
Report Number
14
Report Start Date
8/10/2024
Report End Date
8/11/2024
Operation
Continue RIH w/ BHA #3 f/ 2280' t/ 2907'
Wash and ream f/ 2907' t/ 3319' tag top of fish, CBU
POOH f/ 3319' t/ 30' L/D BHA #3 clean and clear floor, break down cement head.
Service rig and top drive, inspect crown and break linkage, grease draw works and blocks
RIH P/U 3.5'' Cement stinger from surface t/ 529' cross over to 4.5'' DP
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 5/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Trouble shoot COM setting on its own, replace toggle in draworks.
RI Hw/ 3.5'' cement stinger on 4.5'' DP f/ 529' t/ 3316'
Circulate bottoms up stage rate to 5 bpm, 344 psi, spot in and R/U cementers
PJSM, PT lines t/ 2826 psi, pump 20 bbls water ahead followed by 22 bbls 15.8 ppg ceemnt, 13 bbls water, followed by 21 bbls mud, shut down opened bleeder on a vac
R/D circ equipment.
POOH f/ 3316' t/ 2411'
Circulate 2 bottoms up 10 bpm 338 psi, no cement returns to surface, flow check well static,
POOH F/2414'-T/534' racked back 4.5" DP stds in the derrick. B/O XO, L/D 17 jts of 3.5" H563 cmt stinger.
Cleaned & cleared rig floor. Stagged BHA #4 on the catwalk.
P/U 6-3/4" directional BHA #4 as per MWD/DD. M/U 6-3/4" PDC 5 bladed double rowed cutter bit to mud motor. Measured off set- 275.77 degrees. P/U & M/U MWD
tools. Uploaded MWD data. Performed shallow pulse tests (ok). Held PJSM , loaded sources. P/U remainder of BHA T/679'.
RIH on elevators F/679'-T/2748'.
Washed down F/2748', started seeing cmt stringers @ 2867'. and consistently harder cmt @ 2933'. Currently washing down @ 2936'. P/U-60K S/O-50K GPM-184
SPP-846 psi WOB-2K Diff-88 psi MW-9.15 ppg ECD-9.7 ppg
Report Number
15
Report Start Date
8/11/2024
Report End Date
8/12/2024
Operation
Continue washing down f/ 2836' t/ 2890' tag hard cement, Drill cement t/ 2955'
Build trough and time drill f/ 2955' t/ 2966' 1' every 5 min WOB 1-4k, 185 gpm 1280 psi
Drill 6 3/4'' Hole from 2966' t/ 3029' 185 gpm 1280 psi 3-5k WOB
Displace cement contaminated mud with fresh mud
Cont. directional drilling 6 3/4'' production hole F/3029'-T/3630'. P/U-75K S/O-52K ROT-61K GPM-225 SPP-1258 psi RPM-50 TQ-6K Flow-19% Diff-140 psi WOB-2/3K
MW-9.05 ppg ECD-9.91 ppg Max gas- 249 units. Obtained new set of SPR's @ 5301' and pumped 25 bbl Hi-Vis sweep, sweep came back on time with a 60% increase in
cuttings.
Crew change, held PTSM and weekly safety meeting with rig crew. Cont. directional drilling 6 3/4'' production hole F/3630' to current depth of 4007'. P/U-78K S/O-55K
ROT-64K GPM-225 SPP-1266 psi RPM-50 TQ-6K Flow-19% Diff-210 psi WOB-2/3K MW-9.05 ppg ECD-9.98 ppg. Max gas- 143 units. Distance to well plan: 20.54'
20.47' High 1.72' Left
Report Number
16
Report Start Date
8/12/2024
Report End Date
8/13/2024
Operation
Circulate Bottoms up Obtain survey and SPR's, Flow check well static
Make wiper trip f/ 4007' t/ 2922' with no issues.
Service rig and slip and cut driling line 71' 15 wraps
RIH f/ 2922' t/ 4007' sey down and washed and reamed through tight spot at 3059' no other issues washed laast stand to bottom
Continue Drilling 6 3/4 '' Hole section f/ 4007' t/ 4444' 225 gpm 1765 psi 60 rpm 6k tq on bottom max gas 355 units 4-6k WOB MW 9.05 ppg ECD 10.41 ppg 86k PUW 58k
SOW 68k ROT
Cont. directional drilling 6 3/4'' production hole F/4444'-T/4801'. P/U-92K S/O-59K ROT-72K GPM-225 SPP-1837 psi RPM-60 TQ-7K Flow-19% Diff-352 psi WOB-4.5K
MW-9.1 ppg ECD-10.5 ppg Max gas-355 units. Obtained new set of SPR's @ 4507' and pumped 25 bbl Hi-Vis sweep, sweep came back 6 bbls early, with a 50%
increase in cuttings.
Crew change, held PTSM. Cont. directional drilling 6 3/4'' production hole F/4801' to current depth of 5196'. P/U-95K S/O-64K R OT-77K GPM-225 SPP-1985 psi RPM-60
TQ-8K Flow-19% Diff-370 psi WOB-5K MW-9.01 ppg ECD-10.5 ppg. Max gas- 444 units. Distance to well plan: 25.59' 25.50' High 2.11' Left
Report Number
17
Report Start Date
8/13/2024
Report End Date
8/14/2024
Operation
Contine Drilling 6 3/4'' Hole section f/ 5196' t/ 5258' 225 gpm 2000 psi 60 rpm 7.2k tq on bottom, WOB 4-9k, MW 9.15 ppg ECD 10.44 ppg, 95k PUW 64k SOW 77k ROT
Max Gas seen 444 units
Circulate bottoms up, obtain survey and SPR's, Flow check well static.
Make wiper trip f/ 5258' t/ 4008' without issues
Service rig and top drive, clean suction screens 95% packed off, grease blocks and crown, inspect brake linage and draw works.
RIh f/ 4008' t/ 5258' without issues, wash last stand to bottom pump hi vis sweep back 100 stks early 30% increase in cuttings
Drill 6 3/4'' Hole section f/ 5258' t/ 5693' 225 gpm 1980 psi 60 rpm 9k tq on bottom, WOB 4-10k, MW 9.1 ppg ECD 10.44 ppg, 106k PUW 65k SOW 80k ROT Max Gas
seen 152 units
Drill 6 3/4'' Hole section f/ 5693' t/ 6035' 225 gpm 1899 psi 60 rpm 9k tq on bottom, WOB 4-10k, MW 9.1 ppg ECD 10.49 ppg, 114k PUW 68k SOW 86k ROT Max Gas
seen 152 units Pumped sweep at 5880' back 6 bbl early with 25% increase in cuttings.
Drill 6 3/4'' Hole section f/ 6035' t/ 6413' 225 gpm 1899 psi 60 rpm 9k tq on bottom, WOB 4-10k, MW 9.2 ppg ECD 10.39 ppg, 123k PUW 72k SOW 90k ROT Max Gas
seen 227 units
Report Number
18
Report Start Date
8/14/2024
Report End Date
8/15/2024
Operation
Continue Drilling 6 3/4'' Hole Section f/ 6413' t/ 6500' 225 gpm 2000 psi 60 rpm 10.1k tq on bottom, WOB 5-10k, MW 9.3 ppg ECD 10.53 ppg, 127k PUW 76k SOW 93k
ROT Max Gas 269 units
Circulate Bottoms up, Obtain survey and SPR's Flow check well static.
POOH f/ 6500' t/ 5256' had to work through a few tight places slide areas 25-35k over pulls
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 6/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Service rig and top drive, grease blocks and crown, clean suction screens 50% blocked off, inspect draw works.
RIH f/ 5256' t/ 6411' set down Wash and ream last stand to bottom.
Pump Hi Vis Sweep around, Back 100 stks early 30% increase in cuttings, Flow Check well static.
POOH f/ 6500' t/678' without issues. Hole fill: Clac-46.2bbl Act-53.1 lost 6.9bbl.
Rack back HWDP and jars. PJSM. Remove radio active sources from MWD tools. Download MWD data. L/D directional BHA. Bit Graded:1-1-WT-A-X-I-PN-TD
Clean and clear rig floor. Static loss rate of 1.0bbl/hr.
P/U BHA #6. M/U re-run pdc bit, bit sub and 6.625" gauge stabilizer. RIH w/ 9 stands of HWDP and jars.
RIH on elevators f/567' t/1193' P/U-31K, S/O-30K.
Cont RIH on elevators f/1193' t/3293' set down 20k, unable to work past. Wash and ream t/3455' 240GPM=600PSI, 30RPM=3-12k TQ. Cont RIH on elevator f/3450'
t/5364', set down 25k unable to work past. Wash and ream t/5701', 260GPM=1170PSI, 30RPM=6.4K TQ. Cont to RIH on elevators f/5706' t/6456'. Wash last stand to
bottom at 6500'.
CBU at 200GPM=617PSI, 30RPM=9.4K TQ. Max gas=4276 units.
Report Number
19
Report Start Date
8/15/2024
Report End Date
8/16/2024
Operation
Pump 25 bbbl Hi Vis Sweep around, Sweep back on time 15% increase in cuttings, circulate till shakers cleaned up. Flow check well static
POOH f/ 6500' t/ surface with no issues, break stab and bit L/D together
Clean and clear floor, Pull wear ring and set test plug, fill lines and stack with water, run test lines and fittings purge air .
Test BOP's w/ 3.5'' and 4.5'' test joints, test upper lower blinds and annular t/ 250/3000 psi test CMV 1-13 , TIW and Dart, HC R and Man Choke and Kill, Auto and Man
IBOP, 4'' Demco, Electric and man choke tested to 1500 psi, Tested gas alarms and PVT sensors.
R/D test equipment. Pull test plug and install wear ring.
Change out Hyd IBOP and lower IBOP valve on top drive.
Test Hyd and lower IBOP 250/3000psi 5/5min. 1 F/P on Hyd IBOP, funcitoned vale and got a good test.
R/D test equipment. Blow down choke manifold, kill and choke lines. and gas buster. Align well control equipment for drilling.
M/U dumb iron clean out assembly, RIH from derrick w/ 9 stnds of HWDP and jars t/ 567'.
RIH on elevaotrs f/ 567' t/3762'. P/U-73K, S/O-52K.
Fill pipe and CBU at 180GPM=360PSI 40RPM=5.5K TQ. Max gas 2622 units at bottoms up.
Cont to RIH on elevaotr f/3762' t/5521'.
Report Number
20
Report Start Date
8/16/2024
Report End Date
8/17/2024
Operation
Continue RIH f/ 5521' t/ 6500'
CBU 3950 units of gas on bottoms up, Pump Hi Vis Sweep around, back on time no increase in cuttings, continue Circulating racking back stands every hour t/ 6284'
Continue ciruclating and reaming stand racking back stand after each bottoms up t/ 5550'. Dropped hollow drift on stand #91. P/U-110K, S/O-64K, ROT-85K.
250GPM=740PSI, 60RPM=9.5K TQ. MW-9.25ppg.
Continue ciruclating and reaming stand racking back stand after each bottoms up f/5550' t/4804'. P/U-92K, S/O-61K, ROT-74K. 250GPM=680PSI, 60RPM=7.6K TQ.
MW-9.25ppg.
Continue ciruclating and reaming stand racking back stand after each bottoms up f/4804' t/4525'. P/U-84K, S/O-56K, ROT-70K. 250GPM=680PSI, 60RPM=7.6K TQ.
MW-9.3ppg.
Flow check well-slight seepage. POOH on elevators f/4525' t/567'.
Report Number
21
Report Start Date
8/17/2024
Report End Date
8/18/2024
Operation
Rack back 9 stands of HWDP and jar stand. L/D dumb iron clean out assembly. Bit graded:1-1-CT-S-X-I-NO-BHA. Hole fill: Calc-32 bbl, Act-38.7 bbl.
PJSM. R/U Parker TRS equipment. M/U shoe track Baker locing connections. Check floats-good. Cont. to RIH w/ 3.5" liner as per tally f/95' t/2238'. Filling on the fly
topping off every 10. P/U-28K, S/O-25K.
Cont. to RIH w/ 3.5" liner f/2238' t/3707'. Filling on the fly topping off every 10. P/U and M/U Yellow Jacket hanger. Mix and pour pal mix in hanger. Change out elevators
and M/U a stand of 4.5" DP. P/U-38K, S/O-31K.
Circulate pipe volume, ensure packer is clear. 128GPM=240PSI.
TIH w/ 4.5" DP f/3707' t/6500'. Wash last stand to bottom. P/U-80K, S/O-54K. Disp: Calc-52.7bbl, Act-50bbl.
Circulte and condition while R/U cementers. 170GPM=500PSI P/U-80K, S/O-54K.
Halliburton pumped 10 bbls water to flush and fill lines. Shut in at Yellow Jacket cement head and PT lines at 500 psi low 4000 psi high-good tests.
Lined up and pumped 30 bbls 12 ppg Tuned Spacer at 4bpm-480psi, 12% flow, followed with 177 bbls (415 sx) 12.0 ppg Type I II Lead cement at 5 bpm-icp-370 to
fcp-348 psi, 15% flow. Followed lead with 27 bbls (122 sx) 15.3 ppg Type I II Tail cement at 4bpm, icp-385 to fcp-415psi, 11% flow. YJ released dart, Halliburton then
displaced with 10 bbl of water followed by 9.3ppg 6% KCL mud at 4bpm slowing to 3bpm- 124 psi ICP. Saw dart latch wiper plug 36 bbls into displacement as pressure
increased from 263 psi to 1040 psi at 3 bpm. Once plug released pressure dropped and we resumed 3.5 bpm. With 20 bbls to go, reduced rate to 3bpm- 915psi with 10
to go slowed to 2bpm at 1180psi . Bumped liner wiper plug/landing collar66.5 bbls into displacement (calculated at 70 bbls). FCP 1300psi. Halliburton increased to and
held 1815 psi (515 over fcp) for 2 minutes, then bled back to the truck 0.5bbl and floats held. Pressured up to 2300 psi for 2 minutes to set hanger, set down 30k with
hanger set. Pressured up, at 2800 psi set packer bled pressure off, then pressured up to 3500psi to release. PU wt 50K giving us good indication we had released run
tool. CIP at 20:45 on 8/17/2024.
R/D cement hoses and L/D YJ cement head. M/U TD to stump. P/U 10’ to expose dog sub, set down 40k and rotate 5rpm to ensure set. Pressured up to 745 psi on drill
string and picked up. String pressure started dropping, ramped up both pumps and CBU twice at 411 gpm- 680 psi. Had 30 bbls spacer and 53 bbls cement, and 20 bbls
contaminated mud at the shakers, lost 3.6bbl down hole.
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 7/7
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
POOH f/2734' t/150'. P/U-48K, S/O-44K.
Cont. POOH f/105' t/34'. Break down and L/D Yellow Jacket running tool. Clean and clear rig floor.
M/U diffuser on a stnd of DP and flush stack with black water. Break down Cement head and XO's.
M/U Yellow Jacket polish mill. RIH on 4.5" DP f/37' t/2788'. Polish TBR and dress liner top as per YJ rep. 100GPM=174PSI, 7RPM=1.7K TQ.
PJSM with all parties involved displace wll over to CI water. Pump 20 bbl hi-vis spacer and begin pumping CI water. 200GPM=520PSI, 40RPM=3K TQ.
Report Number
22
Report Start Date
8/18/2024
Report End Date
8/19/2024
Operation
Continue Displacing well with CI water, shut down and Monitor well f/ 30 min No Flow test static.
POOOH L/D DP singles Sucking wiper balls through pipe and doping pin and box and installing thread protectors.
R/U and test Liner Lap t/ 3000 psi f/ 30 min Failed 100 psi pressure loss evey 5 min, isolate surface equipment and test again, no change still leaking down hole.
M/U seal Assembly and jt of 8 rnd tubing, cross over to DP, RIH t/ 2786' tag up on seal bore and no go.
R/U and Test down the tubing testing seals, liner and Float equipment t/ 3000 psi f/ 15 min solid test, R/U and test down IA testing liner lap test to 3000 psi f/ 15 min same
bleed rate 100 psi in 5 min, R/D test equipment.
POOH f/ 2786' t/ surface L/D tubing jt and seal assembly, no damage to seals
Service rig and top drive, grease blocks and crown, service floor motor, inspect draw works and brake linkage, change out alternator on floor motor.
P/U YJ liner running tool/dog sub. RIH F/ surface T/2765'. Rotate at 5RPM and set down 35K on liner top with dog sub multiple times to try and expand the packer more.
P/U-54K, S/O-49K
R/U test equipment and test liner lap to 3000psi. Bled off 250PSI in 20 min. Decision made to POOH L/D 4.5" DP and run tie back with DLH packer.
POOH laying down 4.5" DP f/2759 t/2091'. P/U-46K, S/O-39K.
Cont. POOH laying down 4.5" DP f/2091' t/ surface. L/D YJ running tool/dog sub.
Service and inspect crown, blocks, top drive, iron roughneck, drawworks, chain case, gear box, drive line, brake linkage, and floor motor.
RIH w/ remaining 4.5" DP from derrick f/ surface t/1440'. Screw in and pump a string volume to flush DP.
POOH laying down 4.5" DP f/1440' t/550'.
Report Number
23
Report Start Date
8/19/2024
Report End Date
8/20/2024
Operation
Continue POOH L/D DP f/ 550' to surface.
R/U Parker TRS, Pull wear ring, change out elevators.
PJSM, M/U 3.5'' Completion w/ tri point packer RIH t/ 2790' tag up on NoGo, L/D 2 jts of tubing, M/U Space out pups and hanger and llanding jt, land on hanger spaced
off nogo 1'
R/U and test tubing and set packer w/ 3000 psi f/ 30 min good test .59 bbls pumped in .59 bbls bled back, R/U and test IA t/ 3000 psi f/ 30 min good test 1.13 bbls
pumped in 1.13 bbls bled back, R/D test euipment, set TWC
Flush through stack and mud lines, fluch choke and gas buster, flush through pumps and bleeders and pop offs.
N/D flow line and bell nipple. R/D flow box and chains on BOP. Remove choke and kill line. Pressure down accumulators and remov e koomey lines. Open rams doors
and inspect cavities. N/D stack and spacer spool.
N/U dry hole tree. Test void and hanger neck seals to 5000PSI/15min-good test. Couldn't get a test on master valve flanges.
Changed oil in topdrive gear box and swivel. Changed oil filters on floor motor. R/D transfer lines on pits. R/D down degasser. Pull end caps, clean, inspect mud pumps
and reassemble. R/D kelly hose from topdrive. Remove saver sub and bails. Disconnect hydraulix hose from top drive. Cont. working with vault well head rep to get a test
on master valve flanges. Pull night cap and hammer up flanges.
Cont R/D and L/D top drive. L/D torque bushing. Clean and clear rig floor. Lower degasser. Perform maintenance on catwalk winch. Cont. work with vault well head rep.
After hammering up top flange night cap would not go back on. Cleaned up threads and got night cap back on. Test upper flange and master valve held pressure. Opened
master valve wouln't pressure up. Pulled and dressed 2-way check and re-installed. Pressure up 5000psi/15min good test. Install shipping beams.
Field: Beluga River (BRU)
Sundry #: 224-088
State: ALASKA
Rig/Service: HEC 147
Page 1/4
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:9/9/2024 End Date:
Report Number
1
Report Start Date
9/9/2024
Report End Date
9/10/2024
Operation
MOVED OVER TO 233-23T FROM 221-26. STABBED ONTO WELLHEAD. RIH WITH 1-7/16" CABLE HEAD, 1-11/16" X 5' WEIGHT BAR, 1-11/16" X 7' WEIGHT BAR,
1-11/16" CCL, AND JUNK BASKET WITH 2.75" GAGE RING (MAX LENTH = 21.5' , MAX OD = 2.75").
RIH AND SET DOWN AT 6330. MADE 2 ATTEMPTS TO GET DEEPER BUT TAG DEPTH WAS 6330. PU LOGGING FROM 6330-2773'.
PULLED HEAVY COMING ACROSS EVERY JEWELRY DETAIL. BEGAN ATTEMPTIN TO WORK TOOL UP TO 50% BREAKING STRENGTH TO 1000 LBS (UPHOLE
WEIGHT 380 LBS). ABLE TO MOVE DOWNHOLE. ATTEMPTED UPHOLE AT DIFFERENT SPEEDS, 20, 40, 60, 80, 120, AND 160 FPM, BUT NO CHANGE.
STARTED PULLING IN INCREMENTS OF 100 LBS.
PULLED UP TO 2000LBS AT 2773'. TOOLS CAME FREE, UNABLE TO SEE CCL. POOH. PIG TAIL AT END OF WIRE SO TOLLS PULLED OUT OF ROPE
SOCKET. RIG DOWN AND SDFN.
Report Number
2
Report Start Date
9/13/2024
Report End Date
9/14/2024
Operation
Travel from Kenai to Beluga. round up equipment & travel to location. PTW/PJSM. MIRU Pollard slickline.
Ran 2.50" LIB, made multiple passes down & up through packer from 2740'-2825. Going ~30fpm coming up see ~100LB over pull @ 2779' SLM, slight bobbles @ faster
speeds. Made ~10-15 passes and seeing a slight bobble only PUH @ 2779', goes down hole smooth. Continue in hole tag eline fish @ 6322' SLM, POOH, clean
impression of eline FN. Lay down crane to readjust it.
Drift to 6322' W/ CBL drift. ( bow spring cent, 20' x 1.69" D.gun, bow spring cent.) SD @ 6322' SLM, No issue in trouble spot @ 2779'. POOH
RIH W/ 10' x 2.50" dummy guns. SD @ 6322' SLM, No issuse POOH.
RIH W/ 2.25" releasable overshot. Latched E-line TS @ 6322', Hung up at 2755' (Tool string 20' long bottom of fish at 2775' SLM) worked passed after 15 mins, OOH W/
E-line fish all intact. RDMO
Report Number
3
Report Start Date
9/14/2024
Report End Date
9/15/2024
Operation
travel to 214-13, Rig down equipment & move to 233-23T
PTW/PJSM, MIRU AK E-line
RIH W/ CBL, tag @ 6336', log from 6336' to 2650'. Estimated TOC @ 2925'. POOH,RDMO.
Report Number
4
Report Start Date
10/7/2024
Report End Date
10/8/2024
Operation
PJSM, Crew travel to location, Mob equipment to pad, Spot in & rig up.
Nipple up Fox coil BOPE 4-1/16" x 5M bope.
Pressure test BOPE as per approved sundry by AOGGC, witness waived by Jim Regg. 250-low, 3000-high, Perform accumilator draw down test-pass.
Run in the hole to tag @ 6378, Pump 25 bbls H20 down the backside & kick in N2. Unload wellbore with N2 reversing (108 bbls calculated, 111 actual), Pull out of hole
trapping 1900 psi.
Lay down lube & injector for the night.
Report Number
5
Report Start Date
10/14/2024
Report End Date
10/15/2024
Operation
PJSM, Crew mob to location, Spot in & rig up, PIck up lube & tool string, Stab onto well, Pressure test wellhead & lube 250/2500-good.
Run in hole with run #1 (CCL/GPT), Run in hole to tag @ 6356', Fluid level @ 6210', Pull Correlation pass from 6356' to 5000', Pull out of hole.
Run in hole with run #2, (CCl/GUN) (2.5" x 19'), Run in hole & correlate, Perf I7 6334-6353, Draw down well from 1780 to 1545. OG psi: 1545, 5 min: 1546, 10 min: 1544,
15 min: 1542, Pull out of hole.
**2.5", 6 spf, 60 deg, 12 gr
Run in hole with run #3, (CCl/GUN) (2.5" x 4'), Run in hole & correlate, Perf H11 5806-5810, Draw well down from 1545 to 1390. OG psi: 1401, 5 min: 1406, 10 min: 1405,
15 min: 1405 , Pull out of hole.
**2.5", 6 spf, 60 deg, 12 gr
Rig down & secure well for the night
Report Number
6
Report Start Date
10/15/2024
Report End Date
10/16/2024
Operation
PJSM, Crew travel to location, Start & warm equipment, Pick up CCL/GPT.
Run in hole with run #1 CCL/GPT, Tag @ 6356', Fluid @ 5886', Pull out of hole.
Pick up run #2, CCL/PLUG (2.75" x .95), Run in hole, Correlate, Attempt to set plug, No fire, Pull out of hole.
Trouble shoot plug setting tools. Ground on ignitor shorted out shooting signal.
Pick up run #3, CCL/PLUG (2.75" x .95), Run in hole, Correlate, Set plug @ 5796', Tag & log off-good, Pull out of hole.
PTO out on crane. MOB cruz crane to location to lay down Lube. Rig down & secure well for the night.
Report Number
7
Report Start Date
10/18/2024
Report End Date
10/19/2024
Field: Beluga River (BRU)
Sundry #: 324-507
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:224-088
Wellbore API/UWI:50-283-20200-01-0000
Page 2/4
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
PJSM, Crew travel to location, Spot in & rig up equipment, Wait on production to verify & leak check-good, Pick up lube & gun, Stab onto well, Pressure test
250/2500-good.
Pick up run #1, (CCL/GUN) (2.5"), Run in hole & tag 5796', Correlate, Draw down well to 980 psi, Perf H9 5682-5690, OG psi: 980 psi, 5 min: 982, 10 min: 981, 15 min:
979, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg
Draw down well from 979 psi to 830 psi, Monitor pressure build for 15 min lost 3 psi over 15 min 830 to 827, draw down well 157 psi to 670 psi, Pressure built to 673 psi,
Pick up run #2, CCL/GPT, Run in hole to fluid @ 5708', Draw well down to 212 psi, Monitor fluid level with GPT. Fluid level @ 5704 . Pull out of hole.
Rig down & secure well for the night.
Report Number
8
Report Start Date
10/19/2024
Report End Date
10/20/2024
Operation
PJSM, Crew travel to location, Start & warm equipment, Rehead (5/2), Pick up lube & tool string (CCL/GUN). Air tanks froze unable to control grease, Work on frozen air
lines.
Pick up Run #1, (CCL/GUN) (2.5"), Run in hole & correlate, Draw well down to 800 psi, Perf BEL H8 5644-5653, OG psi: 800 psi, 5 min: 807, 10 min: 811, 15 min: 812,
Pull out of hole.
**2.5", 12 g, 6 spf, 60 deg
Check production equipment, Flow well, Draw down from 650 psi monitor for 30 min. pressure built to 693.
Pick up run #2, (CCL/GPT), Run in hole, Fluid level @ 5690', Pull out of hole to 5000' & monitor fluid level while flowing well. Pull out of well fluid stayed @ 5690'.
Secure well, Lay down tools & rehead. Rig down & spot in equipment, to perf both 221-26 & 233-23T.
Report Number
9
Report Start Date
10/20/2024
Report End Date
10/21/2024
Operation
PJSM, Crew swing from 221-23 to 233-23T, Pick up tools, (CCL/GUN), Pressure test 250/2500-good.
Run in hole with run #1, Correlate, Perf H4 5525-5531, 500 lbs overpull to free tools, OG psi: 997, 5 min: 998, 10 min: 998, 15 min: 998, Pull out of hole.
**2.5", 6 spf, 11 g, 60 deg
Secure well & rig down for the night.
Report Number
10
Report Start Date
10/21/2024
Report End Date
10/22/2024
Operation
PJSM, Crew travel to location, Perform maintenace on crane & equipment, Rehead 5/2, Pick up lube & tools (CCL/GR/GUN 2.5"x 10') Stab onto well pressure test
250/2500-good
Run in hole with run #1, (CCL/GR/GUN) (2.5" x 10'), Perform correlation pass, Perf H3 5502-5512, OG psi: 1232, 5 min: 1230, 10 min: 1225, 15 min: 1226, Pull out of
hole.
**2.5", 12 g, 6 spf, 60 deg
Pick up run #2 (CCL/GUN) (2.5" x 6'), Run in hole, Correlate, Pull out of the hole.
Secure the well & rig down for the night.
Report Number
11
Report Start Date
10/22/2024
Report End Date
10/23/2024
Operation
PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tool (CCL/GUN) (2.5"), Pressure test 250/2500,
Run in hole with run #1, CCL/GUN 2.5" x 6', Correlate, Perf H3 5496-5493, OG psi: 1249, 5 min: 1271, 10 min: 1285, 15 min: 1292, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg
Pick up run #2, CCL/GUN 2.5" x 12', Run in the hole, Correlate, Perf H2 5459-5471, OG psi: 1402, 5 min: 1394, 10 min: 1387, 15 min: 1376, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg
Pick up run #3, CCL/GUN 2.5" x 5', Run in the hole, Correlate, BEL H1 5444-5449, OG psi: 1327, 5 min: 1324, 10 min: 1320, 15 min: 1320, Pull out of hole.
**2.5", 12 g, 6 spf, 60 deg,
Pick up run #4, CCL/GR/GUN 2.5" x 3', RUn in the hole, Correlate, Perf BEL H 5376-5379, OG psi: 1300, 5 min: 1303, 10 min: 1303, 15 min: 1303, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg,
Pick up run #5, CCL/GUN 2.5" x 3', Run in hole, Correlate, Perf G5 5201-5204, OG psi: 1310, 5 min: 1311, 10 min: 1310, 15 min: 1310, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg,
Pick up run #6, CCL/GUN 2.5" x 6', Run in the hole, Correlate, Perf G4 5184-5191, OG psi: 1313, 5 min: 1314, 10 min: 1312, 15 min: 1312, Pull out of the hole (tight hole
300lbs overpull to free)
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #7, CCL/GR/GUN 2.5" x 4', Run in the hole, Correlate, Perf G2 5149-5143, OG psi: 1313, 5 min: 1298, 10 min: 1290, 15 min: 1290, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg.
Field: Beluga River (BRU)
Sundry #: 324-507
State: ALASKA
Rig/Service:
Page 3/4
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Secure well & rig down for the night.
Report Number
12
Report Start Date
10/23/2024
Report End Date
10/24/2024
Operation
PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tool (CCL/GR/GUN) (2.5"), Pressure test 250/2500-good,
Run in hole with gun #1, Correlate, while correlating CCL/GR throwing bad signals, Pull out of the hole to swap CCL/GR. Surface test tools-good.
Run in the hole with run #1 (CCL/GR/GUN 2.5" x 5'), Correlate, Attempt to pull into shoot and CCL/GR stopped working, Pull out of hole without firing perf gun.
Run in the hole with run #1 (CCL/GR/GUN 2.5" x 5'), Correlate, BEL G2 5136-5141, OG psi: 928 & flowing, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #2, CCL/GUN 2.5" x 8', Run in the hole, Correlate, Perf BEL G2 5109-5117, OG psi: 733 & Flowing, Pull out of hole
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #3, CCL/GUN 2.5" x 20', Run in hole, Correlate, Perf BEL G 5067-5087, OG psi: 699 & flowing
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #4, CCL/GUN 2.5" x 9', Run in hole, Correlate, Perf F10 5029-5038, OG psi: 723 & flowing, Gun stuck at firing depth. Work string while playing with
choke,Close in build to 855 psi-stable, Open and draw down well to 680 psi- no movement, Work up in increment of 200 lbs to 2200 lbs, Pulled out of rope socket (2600
lbs was 100%). Pull out of hole & secure well.
**2.5", 12 g, 6 spf, 60 deg.
Secure well & rig down for the night.
Report Number
13
Report Start Date
10/24/2024
Report End Date
10/25/2024
Operation
8:00 Arrive @ PWl, gather tools.
9:00 Flight departing for Beluga.
10:45 Sign permits, fire up equipment.
11:30 Stand by for production to clear area around wellhead.
14:00 Rih up on well.
15:00 PT 1500 PSI- pass.
15:20 Rih w/ 2.5 LIB, counter shuts off going in hole, w/t pooh, unknown bottom hole depth.
Ooh w/ impression of e-line rope socket.
17:15 Rih w/ 3 1/2 GS, 3 1/2 bait sub, 1 11/16 Overshot (2.35 OD) to 5016' kb, w/t cant latch, pooh, ooh
sheared, no bait sub.
18:00 Ooh w/ tools, lay down for the night. End ticket.
Report Number
14
Report Start Date
10/25/2024
Report End Date
10/26/2024
Operation
6:00 Morning Safety meeting, talk w/ company rep, sign permits TGSM.
7:15 Rig up on well.
7:30 Rih w/ 3 1/2 GS to 5015' kb, latch overshot from previous day, pooh.
8:35 Rih w/ 1 3/8 JDC (w/ core nut) w/ 2.7 Bell Guide to 5015' kb, w/t jar up 3X, break JD, pooh, ooh w/
broken JD
11:40 Rih w/ 3 1/2 Gs w/ G Bait sub w/ 1 7/16 Overshot to 5015' kb, latch fish, jar up 10X @ 1800 lbs, come
free, pooh.
13:00 Rih w/ 2.5 Lib to 5770' kb, w/t pooh. Ooh no marks.
14:00 Ooh w/ tools, rig down off well.
15:00 Move to 44-36, end ticket.
Report Number
15
Report Start Date
10/29/2024
Report End Date
10/30/2024
Operation
PJSM, Crew swing from 221-26 to 233-23T, Pick up up tool string (CCL/GPT), Pressure test 250/2500-good, Run in hole with GPT to 5700', Fluid Level @ 5490', Log to
4700' Pull out of the hole, Secure well rig down for the night.
Report Number
16
Report Start Date
10/30/2024
Report End Date
10/31/2024
Operation
PJSM, Crew swing from 221-26 to 233-23T, Pick up run #1(CCL/GR/GUN 2.5" x 3'), Pressure test 250/2500-good,
Run in the hole with run #1, Correlate, Perf BEL F10 (5024-5027), OG psi: 752, Open choke & flow well after perfing, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #2, (CCL/GUN 2.5" x 6'), Run in the hole, Correlate, Perf BEL F10 4986-4993, OG psi: 759, Open choke after perfing, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #3, (CCL/GUN 2.5" x 4'), Run in the hole, Correlate, Perf BEL F10 (4981-4984), OG psi: 599, Well flowing while perfing.
**2.5", 12 g, 6 spf, 60 deg.
Field: Beluga River (BRU)
Sundry #: 324-507
State: ALASKA
Rig/Service:
Page 4/4
Well Name: BRU 233-23T
Report Printed: 11/5/2024WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Pick up run #4, (CCL/GUN 2.5" x 5'), Run in the hole, Correlate, Perf BEL F6 (4801-4806), OG psi: 622, Open well after perfing.
**2.5", 12 g, 6 spf, 60 deg.
Secure well & rig down for the night.
Report Number
17
Report Start Date
10/31/2024
Report End Date
11/1/2024
Operation
PJSM, Crew travel to location, Start & warm equipment, Pick up lube & tool string, Pick up run #1 (CCL/GUN 2.5" x 4'), Pressure test 250/2500-good
Run in the hole with run #1, (CCL/GUN 2.5" x 4'), Correlate, Perf BEL F6 (4792-4796), OG psi: 601, Shoot flowing, Pull out of t he hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #2 (CCL/GUN 2.5" x 4'), Run in the hole, Correlate, Perf BEL F5 (4715-4719), OG psi: 655, Shoot flowing, Pull out o f the hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up Run #3 (CCL/GR/GUN 2.5" x 4'), Run in the hole, Correlate, Perf BEL F4 (4695-4699), OG psi: 746, Shut in, Pull out of hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up Run #4 (CCL/GUN 2.5" x 8'), Run in hole, Perf BEL F4 (4673-4681), OG psi: 750, Shut in, Pull out of the hole.
**2.5", 12 g, 6 spf, 60 deg.
Pick up run #5, (CCL/GUN 2.5" x 7') Run in the hole, Correlate, Perf BEL F4 (4635-4641), OG psi: 751, Shut in, Pull out of hole .
**2.5", 12 g, 6 spf, 60 deg.
Secure well, Rig down & release AK Eline.
Field: Beluga River (BRU)
Sundry #: 324-507
State: ALASKA
Rig/Service:
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Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
7,106.00 Original KB/RT Elevation (ft):
93.80
RKB to GL (ft):
18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
2,839.0
Casing
Casing Description:
Surface Run Date:
8/2/2024 Set Depth (ftKB):
2,925.66
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf):
70,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
8.00 Ft/Min (ft/min):
6.10
Run Job:
241-00127 BRU 233-23T Drilling, Drilling -
Drilling, 7/28/2024 06:00
Set Depth (ftKB):
2,925.66 Set Depth (TVD) (ftKB):
2,730.6
Centralizer Detail:
One every other joint up to 300'
Attribute Subtype: Value:
Pipe Reciprocated?:
No Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Casing Hanger 7 5/8 6.87 Cactus 0.64 22.42 21.78
1 Casing Pup Joint 7 5/8 6.87 29.70 L-80 DWC/C 2.07 24.49 22.42
68 Casing Joints 7 5/8 6.87 29.70 L-80 DWC/C 2,815.50 2,839.99 24.49
1 Float Collar 8 1/2 BTC Innovex 1.35 2,841.34 2,839.99
2 Casing Joints 7 5/8 6.87 29.70 L-80 BTC 82.82 2,924.16 2,841.34
1 Float Shoe 8 1/2 BTC Innovex 1.50 2,925.66 2,924.16
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 2,925.66ftKB
Wellbore
Original Hole
Job
241-00127 BRU 233-23T Drilling, Drilling
- Drilling, 7/28/2024 06:00
Cementing Start Date
8/2/2024
Cementing End Date
8/3/2024
Top Depth (ftKB)
21.8
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
21.8
Bottom Depth (ftKB)
2,925.0
Top Measurement Method
Returns to Surface
Pump Start Date
8/2/2024
Cement in Place At
8/3/2024
Final Circulating Pressure (psi)
680.0
Plug Bump Pressure (psi)
1,460.0
Full Return?
No
Returns During Job (%) Volume to Surface (bbl)
39.0
Volume Lost (bbl)
21.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 10.30 73.0 5 HAL
Lead Slurry Lead 409 12.00 170.0 5 HAL
Tail Slurry Tail 174 15.80 42.0 4 HAL
Displacement 8.80 129.0 4 HAL
Post Job Calculations
Subtype Value
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
7,106.00 Original KB/RT Elevation (ft):
93.80
RKB to GL (ft):
18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
2,839.0
Casing
Casing Description:
Surface Run Date:
8/2/2024 Set Depth (ftKB):
2,925.66
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf):
70,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
8.00 Ft/Min (ft/min):
6.10
Run Job:
241-00127 BRU 233-23T Drilling, Drilling -
Drilling, 7/28/2024 06:00
Set Depth (ftKB):
2,925.66 Set Depth (TVD) (ftKB):
2,730.6
Centralizer Detail:
One every other joint up to 300'
Attribute Subtype: Value:
Pipe Reciprocated?:
No Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Casing Hanger 7 5/8 6.87 Cactus 0.64 22.42 21.78
1 Casing Pup Joint 7 5/8 6.87 29.70 L-80 DWC/C 2.07 24.49 22.42
68 Casing Joints 7 5/8 6.87 29.70 L-80 DWC/C 2,815.50 2,839.99 24.49
1 Float Collar 8 1/2 BTC Innovex 1.35 2,841.34 2,839.99
2 Casing Joints 7 5/8 6.87 29.70 L-80 BTC 82.82 2,924.16 2,841.34
1 Float Shoe 8 1/2 BTC Innovex 1.50 2,925.66 2,924.16
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 2,925.66ftKB
Wellbore
Original Hole
Job
241-00127 BRU 233-23T Drilling, Drilling
- Drilling, 7/28/2024 06:00
Cementing Start Date
8/2/2024
Cementing End Date
8/3/2024
Top Depth (ftKB)
21.8
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
21.8
Bottom Depth (ftKB)
2,925.0
Top Measurement Method
Returns to Surface
Pump Start Date
8/2/2024
Cement in Place At
8/3/2024
Final Circulating Pressure (psi)
680.0
Plug Bump Pressure (psi)
1,460.0
Full Return?
No
Returns During Job (%) Volume to Surface (bbl)
39.0
Volume Lost (bbl)
21.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 10.30 73.0 5 HAL
Lead Slurry Lead 409 12.00 170.0 5 HAL
Tail Slurry Tail 174 15.80 42.0 4 HAL
Displacement 8.80 129.0 4 HAL
Post Job Calculations
Subtype Value
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Casing
Siner
Welluore
Welluore Name:
Sidetrack 1 Total f epth obWelluore Dbt( BK:6,500.00 ) riginal ( B/RT OleEation DbtK:93.80
R( B to v S DbtK:18.50 ( B-Casing Glange f istance DbtK: ( B-TLuing Fanger f istance DbtK:
PBTf s
fepthDbt( BK:
Casing
Casing f escription:
Liner RLn f ate:
8/17/2024 Het f epth Dbt( BK:6,498.00
Casing Weight on Hlips D1000lubK:PickUpWeightD1000lubK:80,000.0 Block Weight D1000lubK:15,000.0
Make-Up Contractor:
Parker Casing NLmuer Frs to RLn DhrK:9.50 Gt/Min Dbt/minK:11.40
RLn Jou:
241-00127 BRU 233-23T Drilling, Drilling -
Drilling, 7/28/2024 06:00
Het f epth Dbt( BK:6,498.00 Het f epth DTVf KDbt( BK:6,220.5
Centralizer f etail:
112
AttriuLte HLutype: ValLe:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Gloat Gailed?:
No
Test HLutype: PressLre DpsiK:
Casing D) r SinerKf etails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner Hanger 6.53 4.78 35.48 2,788.60 2,753.12
1 XO 5 1/2 3.92 H563 2.24 2,790.84 2,788.60
43 Blank Liner 3 1/2 2.87 9.20 L-80 H563 1,331.73 4,122.57 2,790.84
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.29 4,137.86 4,122.57
17 Blank Liner 3 1/2 2.87 9.20 L-80 H563 528.22 4,666.08 4,137.86
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.43 4,681.51 4,666.08
14 Blank Liner 3 1/2 2.87 9.20 L-80 H563 438.39 5,119.90 4,681.51
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 14.91 5,134.81 5,119.90
18 Blank Liner 3 1/2 2.87 9.20 L-80 H563 563.73 5,698.54 5,134.81
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 14.81 5,713.35 5,698.54
23 Blank Liner 3 1/2 2.87 9.20 L-80 H563 720.14 6,433.49 5,713.35
1 Float-Landing Collar 4 1/2 2.41 L-80 IBT 1.69 6,435.18 6,433.49
2 Blank Liner 3 1/2 2.87 9.20 L-80 IBT 60.91 6,496.09 6,435.18
1 Float Shoe 4 1/2 2.41 IBT 1.91 6,498.00 6,496.09
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Siner Ceu ent
Ceu entef mtring
Sinerd, d295.66KtBW
lebbOo r e
HriginabJ obe
4oO
12- 066- 17 WRU 133013T DribbingdDribbing
0Dribbingd 7/15/1612 6, 866
Ceu enting mtart Date
5/- 7/1612
Ceu enting : nf Date
5/- 7/1612
Top DeptEhKtBW(
1d91) .6
Cement Stages
Stage Number: 1
Description
Siner Ceu ent
Top DeptEhKtBW(
1d91) .6
Wottou DeptEhKtBW(
,d295.6
Top MeasPreu ent MetEof
CWS
FPu p mtart Date
5/- 7/1612
Ceu ent in Fbace At
5/- 7/1612
?inabCircPbating FressPre hpsi(
-d366.6
FbPg WPu p FressPre hpsi(
-d566.6
?PbbRetPrnN
%o
RetPrns DPring 4oOhV (
-66
LobPu e to mPrKa c e hOOb(
)3.6
LobPu e So s t hOOb(
3.,
WPu p FbPgN
Yes
?boat ?aibef N
%o
Fipe Reciprocatef N
Yes
Fipe Rotatef N
%o
mbPrry Type Cbass Au oPnt hsacks( YiebfhKt³/sack( Dens hbO/ g a b(
ActPabLobPu e
FPu pef hOOb(
CabcPbatef
LobPu e FPu pef
hOOb(Q Avg hOOb/u in( FPu p Usef
FreKbPsEhmpacer(- 1.66 36.6 36.6 2 J abbiOPrton
Seaf mbPrry A 2- ) 1.32 - 1.66 - 77.6 - 77.6 ) J abbiOPrton
TaibmbPrry A - 11 2.76 - ) .36 17.6 17.6 2 J abbiOPrton
Dispbaceu ent 9.1) ,,.) ,9.7 2 JabbiOPrton
Post Job Calculations
mPOtype LabPe
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Casing
Siner
Welluore
Welluore Name:
Sidetrack 1 Total f epth obWelluore Dbt( BK:6,500.00 ) riginal ( B/RT OleEation DbtK:93.80
R( B to v S DbtK:18.50 ( B-Casing Glange f istance DbtK: ( B-TLuing Fanger f istance DbtK:
PBTf s
fepthDbt( BK:
Casing
Casing f escription:
Liner RLn f ate:
8/17/2024 Het f epth Dbt( BK:6,498.00
Casing Weight on Hlips D1000lubK:PickUpWeightD1000lubK:80,000.0 Block Weight D1000lubK:15,000.0
Make-Up Contractor:
Parker Casing NLmuer Frs to RLn DhrK:9.50 Gt/Min Dbt/minK:11.40
RLn Jou:
241-00127 BRU 233-23T Drilling, Drilling -
Drilling, 7/28/2024 06:00
Het f epth Dbt( BK:6,498.00 Het f epth DTVf KDbt( BK:6,220.5
Centralizer f etail:
112
AttriuLte HLutype: ValLe:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Gloat Gailed?:
No
Test HLutype: PressLre DpsiK:
Casing D) r SinerKf etails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner Hanger 6.53 4.78 35.48 2,788.60 2,753.12
1 XO 5 1/2 3.92 H563 2.24 2,790.84 2,788.60
43 Blank Liner 3 1/2 2.87 9.20 L-80 H563 1,331.73 4,122.57 2,790.84
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.29 4,137.86 4,122.57
17 Blank Liner 3 1/2 2.87 9.20 L-80 H563 528.22 4,666.08 4,137.86
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.43 4,681.51 4,666.08
14 Blank Liner 3 1/2 2.87 9.20 L-80 H563 438.39 5,119.90 4,681.51
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 14.91 5,134.81 5,119.90
18 Blank Liner 3 1/2 2.87 9.20 L-80 H563 563.73 5,698.54 5,134.81
1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 14.81 5,713.35 5,698.54
23 Blank Liner 3 1/2 2.87 9.20 L-80 H563 720.14 6,433.49 5,713.35
1 Float-Landing Collar 4 1/2 2.41 L-80 IBT 1.69 6,435.18 6,433.49
2 Blank Liner 3 1/2 2.87 9.20 L-80 IBT 60.91 6,496.09 6,435.18
1 Float Shoe 4 1/2 2.41 IBT 1.91 6,498.00 6,496.09
Updated report is attached. -bjm
Page 1/1
Well Name: BRU 233-23T
Report Printed: 11/5/2024
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Siner Ceu ent
Ceu entef mtring
Sinerd, d295.66KtBW
lebbOo r e
HriginabJ obe
4oO
12- 066- 17 WRU 133013T DribbingdDribbing
0Dribbingd 7/15/1612 6, 866
Ceu enting mtart Date
5/- 7/1612
Ceu enting : nf Date
5/- 7/1612
Top DeptEhKtBW(
1d91) .6
Cement Stages
Stage Number: 1
Description
Siner Ceu ent
Top DeptEhKtBW(
1d91) .6
Wottou DeptEhKtBW(
,d295.6
Top MeasPreu ent MetEof
CWS
FPu p mtart Date
5/- 7/1612
Ceu ent in Fbace At
5/- 7/1612
?inabCircPbating FressPre hpsi(
-d366.6
FbPg WPu p FressPre hpsi(
-d566.6
?PbbRetPrnN
%o
RetPrns DPring 4oOhV (
-66
LobPu e to mPrKa c e hOOb(
)3.6
LobPu e So s t hOOb(
3.,
WPu p FbPgN
Yes
?boat ?aibef N
%o
Fipe Reciprocatef N
Yes
Fipe Rotatef N
%o
mbPrry Type Cbass Au oPnt hsacks( YiebfhKt³/sack( Dens hbO/ g a b(
ActPabLobPu e
F Pu p e f hOOb(
CabcPbatef
LobPu e FPu pef
hOOb(Q Avg hOOb/u in( FPu p Usef
FreKbPsEhmpacer(- 1.66 36.6 36.6 2 J abbiOPrton
Seaf mbPrry A 2- ) 1.32 - 1.66 - 77.6 - 77.6 ) J abbiOPrton
TaibmbPrry A - 11 2.76 - ) .36 17.6 17.6 2 J abbiOPrton
Dispbaceu ent 9.1) , , .) , 9.7 2 J abbiOPrton
Post Job Calculations
mPOtype LabPe
Updated report is attached. -bjm
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/30/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241030
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BRU 221-26 50283202010000 224098 10/20/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf
BRU 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf
GP-ST-18742-33 50733203060000 177032 10/9/2024 AK E-LINE LeakDetect/Packer
IRU 11-06 50283201300000 208184 10/4/2024 AK E-LINE Plug/Perf
MPU B-28 50029235660000 216027 10/4/2024 READ CaliperSurvey
MPU F-13 50029225490000 195027 10/15/2024 READ CaliperSurvey
MPU L-36 50029227940000 197148 10/17/2024 READ CaliperSurvey
MRU G-01RD 50733200370100 191139 10/10/2024 AK E-LINE Hoist
NCIU A-21 50883201990000 224086 10/8/2024 AK E-LINE CBL
NCIU B-01B 50883200930200 224097 10/1/2024 AK E-LINE CBL
NCIU B-01B 50883200930200 224097 10/11/2024 AK E-LINE Perf
PBU 06-18B 50029207670200 223071 10/2/2024 HALLIBURTON RBT
PBU 14-32B 50029209990200 224073 10/13/2024 HALLIBURTON RBT
PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON RBT
PBU C-18B 50029207850200 209071 10/2/2024 HALLIBURTON WSTT
PBU NK-26A 50029224400100 218009 10/14/2024 HALLIBURTON PPROF
PCU 02A 50283200220100 224110 9/30/2024 AK E-LINE CBL
PCU 02A 50283200220100 224110 10/4/2024 AK E-LINE Perf
SDI 3-25B 50029221250200 203021 10/17/2024 AK E-LINE Patch
Please include current contact information if different from above.
T39726
T39727
T39728
T39732
T39733
T39734
T39735
T39736
T39737
T39738
T39739
T39739
T39740
T39741
T39742
T39742
T39743
T39744
T39744
T39745
BRU 233-23T 50283202000000 224088 10/14/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.01 13:27:33 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 9/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240927
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF
BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL
END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey
KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF
MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey
MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey
MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut
MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut
MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug
NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL
NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF
NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog
PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch
PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL
PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF
PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL
PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL
PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF
Please include current contact information if different from above.
T39593
T39594
T39595
T39596
T39597
T39598
T39599
T39600
T39601
T39602
T39603
T39603
T39604
T39605
T39605
T39605
T39605
T39606
T39606
T39607
T39608
T39609
T39609
T39610
T39611
BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.27 14:47:28 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson
Cc:Donna Ambruz
Subject:RE: BRU 233-23T (PTD# 224-088) Sundry # 324-507 Cement Bond log
Date:Wednesday, September 18, 2024 12:11:00 PM
Chad,
Hilcorp has approval to proceed with the sundried perf intervals.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Monday, September 16, 2024 2:53 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 233-23T (PTD# 224-088) Sundry # 324-507 Cement Bond log
Bryan,
Please find attached the cement bond log for BRU 233-23T.
Looks like good cement to the bottom of surface casing @ 2925 then cement in the liner lap to
the liner top packer at 2810.
Let us know if we are good with proposed perfs listed in the sundry (Top of perfs @ 4022’).
Thanks
Chad Helgeson
Operations Engineer
Kenai Asset Team
907-777-8405 - O
907-229-4824 - C
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 deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2
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):
6,500'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
DHL Ret Pkr, LTP; N/A 2,717' MD / 2,543' TVD, 2,753' MD / 2,575' TVD; N/A
6,223'6,433'6,156'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 233-23TCO 802
Same
6,221'3-1/2"
~2,057psi
3,710'
N/A
Length
September 17, 2024
Tieback 3-1/2"
6,498'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
2,925'
Size
120'
2,925'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.3# / L-80
TVD Burst
2,787'
10,160psi
2,730'
Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 21127, ADL 17658, ADL 21128
224-088
50-283-20200-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
chelgeson@hilcorp.com
907-777-8405
Noel Nocas, Operations Manager 907-564-5278
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:
m
n
P
s
66
t
2
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 7:49 am, Sep 06, 2024
Noel Nocas
(4361)
Digitally signed by
Noel Nocas (4361)
Date: 2024.09.05
16:52:37 -08'00'
324-507
Submit CBL to AOGCC and obtain approval before perforating.
BJM 9/10/24
DSR-9/11/24SFD 9/10/2024
X
10-407
CT BOP test to 3000 psi.
*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.09.11 18:47:26 -05'00'09/11/24
RBDMS JSB 091624
Well Prognosis
Well Name: BRU 233-23T API Number: 50-283-20200-00-00
Current Status: Gas Producer Permit to Drill Number: 224-088
First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C)
Second Call Engineer: Scott Warner (907) 830-8863
Maximum Expected BHP: 2,665 psi @ 6077’ TVD (Based on 0.44 psi/ft gradient)
Max. Potential Surface Pressure: 2,057 psi (Based on 0.1 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.71 psi/ft using 13.66 ppg EMW FIT at the surface casing shoe 8/3/24
Shallowest Potential Perf TVD: MPSP/(0.71-0.1) = 2057 psi / 0.61 = 3372‘ TVD
Top of Pools per CO 802: Sterling-Beluga Gas Pool: 3,441’ MD, ~3,202' TVD
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 233-23T is the fourth of five grass roots wells drilled in the 2024 Beluga drilling campaign targeting the
Sterling and Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen,
complete a CBL and perforate multiple Beluga sands. All sands lie in the Sterling Beluga Gas Pool.
Wellbore Conditions:
- Liner full of 9.3 ppg 6% KCl mud
- Tubing and IA displaced to 8.4 ppg CIW
- T & IA pressure tested to 3000 psi
- The well had a leaking liner top packer, so a production packer was run with the tail stabbed into the
liner seals, and tubing & IA pressure tested to 3000 psi.
Pre-Sundry work:
1. Review all approved COAs
2. MIRU E-line and pressure control equipment
3. Log well with CBL tool in 3-1/2” liner (send results to AOGCC to review)
4. RDMO E-line
Sundry Procedure:
1. MIRU Coil Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high
a. Provide AOGCC 48hr notice for BOP test
3. RIH & clean out wellbore to PBTD (~6433’), displace liner to 8.4 ppg water
4. Reverse out wellbore with nitrogen, trap ~1700 psi on wellbore
o ~56 bbls total wellbore volume
5. RDMO coil tubing
6. RU E-line, PT lubricator to 2500 psi
7. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically
targeting 20% underbalance)
8. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up:
Pool Top (Sterling A1) 3441’ MD 3202’ TVD
Well Prognosis
Planned Interval (Beluga D – I) 4022’ – 6353’ MD 3757’ – 6077’ TVD
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
a. Above perfs are in the Sterling-Beluga Gas Pool governed by CO 802.
b. Pending well production, all perf intervals may not be completed
9. RDMO
10. Turn well over to production & flow test well
11. Test SVS as necessary once well has reached stable flow rates
a. Notify state 24hrs prior to testing within 5 days of stable production
Coil Procedure (Contingency)
If necessary to cleanout or unload well with coiled tubing:
1. MIRU Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low
2. Provide AOGCC 24hrs notice of BOP test
3. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth
4. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen
a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole
5. RDMO coil tubing
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
Updated by CAH 09-04-24
CURRENT SCHEMATIC
Beluga River Unit
BRU 233-23T
PTD: 224-088
API: 50-283-20200-00-00
PBTD = 6,433’ / TVD = 6,156’
TD = 6,500’ / TVD = 6,223’
RKB = 19.85’
PB1
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01”Surf 120’
7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,925’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,788’6,498’
TUBING DETAIL
3-1/2"Prod Tieback 9.3 L-80 EUE 8RD 2.992”Surf 2,787’
3/4
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 20’2.992”11”Cactus CTF-ONE-CTL Hanger w/ 4” Type H BPV profile
2 2,717’2.992”6.510”DHL Retrievable packer, pinned @ 36K release
3 2,753’4.875”6.540”Ranger Liner hanger w/ Scout packer
4 2,787’2.930”4.630”Seal Stem (1’ off no-go 10ft overall length)
OPEN HOLE / CEMENT DETAIL
7-5/8"170 bbls of 12 ppg lead followed by 42 bbls of 15.8 ppg tail, w/39 bbls of returns to
surface 8/2/24.
PB1
Original PB1 hole drilled to 7106 with 3-1/2” casing run to 7106 and cemented, but
when trying to release from liner hanger, tubing parted at 3319’. Spotted a 22bbl
15.8 ppg cement plug @ 3316’. Drilled through cement plug at 2966’ for new hole.
3-1/2”177 bbls of 12 ppg lead followed by 27 bbls of 15.3 ppg tail in 6.75” hole. 53 bbls of
Cement returned 8/17/24.
6-3/4”
hole
2
1
NOTES
A second packer was run due to the first packer leaking, August 2024
Short Joints (~15ft)4,122’ (RA Tag) , 4666’, 5120’, 5698 (RA Tag)
RA 5,698’
RA 4,122’
Updated by DMA 09-04-24
PROPOSED
Beluga River Unit
BRU 233-23T
PTD: 224-088
API: 50-283-20200-00-00
PBTD = 6,433’ / TVD = 6,156’
TD = 6,500’ / TVD = 6,223’
RKB = 19.85’
PB1
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01”Surf 120’
7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,925’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”2,788’6,498’
TUBING DETAIL
3-1/2"Prod Tieback 9.3 L-80 EUE 8RD 2.992”Surf 2,787’
3/4
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 20’2.992”11”Cactus CTF-ONE-CTL Hanger w/ 4” Type H BPV profile
2 2,717’2.992”6.510”DHL Retrievable packer, pinned @ 36K release
3 2,753’4.875”6.540”Ranger Liner hanger w/ Scout packer
4 2,787’2.930”4.630”Seal Stem (1’ off no-go 10ft overall length)
OPEN HOLE / CEMENT DETAIL
7-5/8"170 bbls of 12 ppg lead followed by 42 bbls of 15.8 ppg tail, w/39 bbls of returns to
surface 8/2/24.
PB1
Original PB1 hole drilled to 7106 with 3-1/2” casing run to 7106 and cemented, but when
trying to release from liner hanger, tubing parted at 3319’. Spotted a 22bbl 15.8 ppg
cement plug @ 3316’. Drilled through cement plug at 2966’ for new hole.
3-1/2”177 bbls of 12 ppg lead followed by 27 bbls of 15.3 ppg tail in 6.75” hole. 53 bbls of
Cement returned 8/17/24. TOC based on CBL run xxxx TBD..
6-3/4”
hole
2
1
PERFORATION DETAIL
Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments
Pool Top Sterling A1 - 3,441’ MD / 3,202’ TVD
Beluga D ±4,022'±4,027'±3,757'±3,762'±5'Proposed TBD
Beluga D1 ±4,035'±4,057'±3,769'±3,791'±22'Proposed TBD
Beluga D3 ±4,069'±4,093'±3,803'±3,827'±24'Proposed TBD
Beluga D5 ±4,155'±4,163'±3,888'±3,896'±9'Proposed TBD
Beluga D6 ±4,201'±4,211'±3,934'±3,944'±10'Proposed TBD
Beluga D6 ±4,221'±4,228'±3,954'±3,961'±8'Proposed TBD
Beluga E ±4,270'±4,276'±4,003'±4,009'±5'Proposed TBD
Beluga E ±4,285'±4,290'±4,018'±4,023'±5'Proposed TBD
Beluga E3 ±4,342'±4,347'±4,075'±4,080'±5'Proposed TBD
Beluga E4 ±4,413'±4,420'±4,145'±4,152'±6'Proposed TBD
Beluga E5 ±4,472'±4,491'±4,204'±4,223'±19'Proposed TBD
Beluga E6 ±4,501'±4,505'±4,233'±4,238'±4'Proposed TBD
Beluga E6 ±4,531'±4,535'±4,263'±4,267'±4'Proposed TBD
Beluga F4 ±4,635'±4,641'±4,367'±4,373'±7'Proposed TBD
Beluga F4 ±4,673'±4,681'±4,404'±4,412'±8'Proposed TBD
Beluga F4 ±4,695'±4,699'±4,426'±4,430'±4'Proposed TBD
Beluga F5 ±4,715'±4,719'±4,446'±4,450'±4'Proposed TBD
Beluga F6 ±4,776'±4,780'±4,507'±4,511'±4'Proposed TBD
Beluga F6 ±4,792'±4,796'±4,523'±4,527'±4'Proposed TBD
Beluga F6 ±4,801'±4,806'±4,532'±4,537'±5'Proposed TBD
Beluga F7 ±4,945'±4,955'±4,675'±4,685'±9'Proposed TBD
Beluga F10 ±4,981'±4,984'±4,711'±4,714'±4'Proposed TBD
Beluga F10 ±4,986'±4,993'±4,716'±4,723'±7'Proposed TBD
Beluga F10 ±5,024'±5,027'±4,754'±4,757'±3'Proposed TBD
Beluga F10 ±5,029'±5,038'±4,759'±4,768'±9'Proposed TBD
Perforation Detail Continued on Following Page
RA 5,698’
RA 4,122’
NOTES
A second packer was run due to the first packer leaking, August 2024
Short Joints (~15ft)4,122’ (RA Tag) , 4666’, 5120’, 5698 (RA Tag)
Updated by DMA 09-04-24
PROPOSED
Beluga River Unit
BRU 233-23T
PTD: 224-088
API: 50-283-20200-00-00
Perforation Detail Continued From Previous Page
PERFORATION DETAIL
Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments
Pool Top Sterling A1 - 3,441’ MD / 3,202’ TVD
Beluga G ±5,067' ±5,088' ±4,797' ±4,818' ±21' Proposed TBD
Beluga G2 ±5,109' ±5,117' ±4,839' ±4,847' ±8' Proposed TBD
Beluga G2 ±5,136' ±5,140' ±4,866' ±4,870' ±5' Proposed TBD
Beluga G2 ±5,149' ±5,153' ±4,879' ±4,883' ±4' Proposed TBD
Beluga G4 ±5,184' ±5,191' ±4,914' ±4,921' ±7' Proposed TBD
Beluga G5 ±5,201' ±5,205' ±4,931' ±4,935' ±3' Proposed TBD
Beluga H ±5,376' ±5,379' ±5,105' ±5,108' ±3' Proposed TBD
Beluga H1 ±5,444' ±5,449' ±5,173' ±5,178' ±5' Proposed TBD
Beluga H3 ±5,486' ±5,493' ±5,214' ±5,221' ±7' Proposed TBD
Beluga F5 ±4,715' ±4,719' ±4,446' ±4,450' ±4' Proposed TBD
Beluga F6 ±4,776' ±4,780' ±4,507' ±4,511' ±4' Proposed TBD
Beluga F6 ±4,792' ±4,796' ±4,523' ±4,527' ±4' Proposed TBD
Beluga F6 ±4,801' ±4,806' ±4,532' ±4,537' ±5' Proposed TBD
Beluga F7 ±4,945' ±4,955' ±4,675' ±4,685' ±9' Proposed TBD
Beluga F10 ±4,981' ±4,984' ±4,711' ±4,714' ±4' Proposed TBD
Beluga F10 ±4,986' ±4,993' ±4,716' ±4,723' ±7' Proposed TBD
Beluga F10 ±5,024' ±5,027' ±4,754' ±4,757' ±3' Proposed TBD
Beluga F10 ±5,029' ±5,038' ±4,759' ±4,768' ±9' Proposed TBD
Beluga G ±5,067' ±5,088' ±4,797' ±4,818' ±21' Proposed TBD
Beluga G2 ±5,109' ±5,117' ±4,839' ±4,847' ±8' Proposed TBD
Beluga G2 ±5,136' ±5,140' ±4,866' ±4,870' ±5' Proposed TBD
Beluga G2 ±5,149' ±5,153' ±4,879' ±4,883' ±4' Proposed TBD
Beluga G4 ±5,184' ±5,191' ±4,914' ±4,921' ±7' Proposed TBD
Beluga G5 ±5,201' ±5,205' ±4,931' ±4,935' ±3' Proposed TBD
Beluga H ±5,376' ±5,379' ±5,105' ±5,108' ±3' Proposed TBD
Beluga H1 ±5,444' ±5,449' ±5,173' ±5,178' ±5' Proposed TBD
Beluga H3 ±5,486' ±5,493' ±5,214' ±5,221' ±7' Proposed TBD
Beluga H3 ±5,502' ±5,512' ±5,230' ±5,240' ±10' Proposed TBD
Beluga H8 ±5,644' ±5,653' ±5,372' ±5,381' ±9' Proposed TBD
Beluga H9 ±5,682' ±5,690' ±5,409' ±5,417' ±9' Proposed TBD
Beluga H11 ±5,806' ±5,810' ±5,533' ±5,537' ±5' Proposed TBD
Beluga I7 ±6,334' ±6,353' ±6,058' ±6,077' ±19' Proposed TBD
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard 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 Transport. 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 Nitrogen vendor 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 Transport.
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: 9/06/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: BRU 233-23T + PB1
PTD: 224-088
API: 50-283-20200-00-00 (BRU 233-23T)
API: 50-283-20200-70-00 (BRU 233-23TPB1)
FINAL LWD FORMATION EVALUATION LOGS (07/31/2024 to 08/14/2024)
DGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
T39518
T39519
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.06 11:54:02 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Joshua Riley - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:BOPE Test Report Rig 147 BRU 233-23T
Date:Monday, August 19, 2024 4:49:58 PM
Attachments:BRU 233-23T MIT 8-19-24.xlsx
Here is the MIT for BRU 233-23T
Josh Riley
Hilcorp DSM
(907)776-6776
Cell (907)252-1211
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.
%HOXJD5LYHU8QLW7
37'
Submit to:
OOPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240880 Type Inj N Tubing 0 3150 3130 3125 Type Test P
Packer TVD 2536 BBL Pump 0.6 IA 0 20 20 20 Interval I
Test psi 3000 BBL Return 0.6 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240880 Type Inj N Tubing 0 135 140 140 Type Test P
Packer TVD 2536 BBL Pump 1.1 IA 0 3170 3170 3170 Interval I
Test psi 3000 BBL Return 1.1 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska LLC
Beluga Rive Unit, BRU 233-23T, J Pad
Josh Riley
08/19/24
Notes:Rig tested after completion ran, pre rig down
Notes:
Notes:
Notes:
BRU 233-23T
BRU 233-23T
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
MMechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Rig Tested after completion ran, pre rig down
Notes:
Notes:
Form 10-426 (Revised 01/2017)2024-0819_MITP_BRU_233-23T_2tests
999
9 9
999
9 9
9
9
- 5HJJ
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
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):
±3,996'3,319'
Casing Collapse
Structural
Conductor
Surface 7150
Intermediate
Production
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone: 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
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
Drilling Manager
Bryan McLellan
±3,750'
N/A BRU 233-23T
Sterling Beluga Gas PoolSterling Beluga Gas PoolBeluga River Unit
Yes
±3,750'±3,996'2441 N/A
Subsequent Form Required:
Suspension Expiration Date:
TVD
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
Length Size
AOGCC USE ONLY
8/12/2024
Tubing Grade:Tubing MD (ft):
N/A
Perforation Depth TVD (ft):
N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL 21127, ALD 17658, ADL 21125
224-088
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-283-20200-00-00
Hilcorp Alaska, LLC
Proposed Pools:
Burst
N/A
MD
9470
120'
2,733'
120'
2,925'
16"
7-5/8"
120'
2,925'
Perforation Depth MD (ft):
N/A N/A
8/11/2024
N/A
N/A
m
n
P
s
66
t
_
c
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Drilling Manager
08/12/24
Monty M
Myers
324-466
By Grace Christianson at 4:00 pm, Aug 12, 2024
DSR-8/12/24SFD 8/12/2024
ADL 21128 SFD
BJM 8/15/24
10-407
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.08.15 16:28:53
-08'00'08/15/24
RBDMS JSB 081624
Well Prognosis
Well: BRU 233-23T
Date: 8-12-24
Well Name:BRU 233-23T API Number:50-283-20200-00-00
Current Status:Drilling 6-3/4” Hole
Estimated Start Date:8/11/24 Rig:Rig 147
Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:8/12/24
Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-088
First Call Engineer:Sean McLaughlin (907)-223-6784 (M)
Second Call Engineer
AFE Number:
Brief Well Summary:
The 3-1/2” liner backed off while performing a left-hand release after a failed hydraulic release. There is
cemented liner from TD to 3319’(TOF). The 7-5/8” shoe is at 2925’.
Operations Conducted to date:
1. RIH to TOF with cleanout assembly tag @ 3,319’. CBU, POOH, LD Cleanout BHA.
2. P/U & M/U 534’ of 3.5” H563 cmt stinger, XO to 4.5” DP. RIH T/3317’. R/U HES cementers. Pumped and
spotted a 500’ balanced cmt plug on top of fish. POOH above cmt top @ 2414’, dropped wiper ball and
CBU x2 with no cmt observed at surface. POOH, racked back 4.5” DP, L/D 3.5” cmt stinger. P/U 6-3/4”
Directional BHA #4. RIH T/2748’. Washed down F/2748’, started seeing cmt stringers @ 2867’ and
consistently harder cmt @ 2933'.
3. Cont. washing down F/2936’, tagged hard cmt @ 2890’. Drilled cmt F/2890’-T/2955’. Built trough
F/2935’-T/2955’. Time drilled F/2955’-T/2966’ holding– 30° R tool face. Verified kick off with surveys.
Pumped Hi-Vis sweep around, back on time with a 60 increase. Drilled ahead to current depth of 3996’.
Plan Forward:
1. Drill 6-3/4” hole to TD of ~7,116’
2. Run 3-1/2” Liner and Cement
3. Run Tieback Assembly
4. ND / NU RDMO
Attachments
1.Current Schematic
2.Proposed Schematic
Updated by CJD 8-12-2024
Current SCHEMATIC
Beluga River Unit
BRU 233-23T
PTD:TBD
API: TBD
TD = 7,106’ / TVD = 6,844’
RKB to GL = 18.5’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01”Surf 120’
7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,925’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”±3,319’7,106’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 2,935’--Trough 2935’-2955’ – Kickoff for sidetrack
2 3,319’2.992”3.500”TOF – 3-1/2” Parted Liner
3 3,996’-6.750”6-3/4” Hole Depth @0600 8/12/24
6-3/4”
hole
2
1
Updated by CJD 8-12-2024
PROPOSED SCHEMATIC
Beluga River Unit
BRU 233-23T
PTD:224-088
API: 50-283-20200-00-00
PBTD = ±7,020’ / TVD = 6,758’
TD = 7,116’ / TVD = 6,844’
RKB to GL = 18.5’
PB1
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01”Surf 120’
7-5/8"Surf Csg 29.7 L-80 GBCD 6.875”Surf 2,925’
3-1/2"Prod Lnr 9.2 L-80 HYD 563 2.992”±2,725’7,106’
3-1/2"Prod Tieback 9.2 L-80 EUE 2.992”Surf ±2,725’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 ±1,500 2.813”3.500”Chemical Injection Sub
2 2,725’4.875”6.540”Liner hanger / LTP Assembly
3 2,725’4.790”6.340”Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8"Est. TOC @ Surface (75% Lead excess)
3-1/2”Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
1
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: Sidetrack BRU 233-23T (224-088)
Date:Monday, August 12, 2024 12:58:00 PM
Hilcorp has approval to proceed with this plan. Please follow up with a sundry.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
-----Original Message-----
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Saturday, August 10, 2024 10:47 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Sidetrack BRU 233-23T (224-088)
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.
Bryan,
Last night the 3-1/2” liner backed off while performing a LH release after a failed hydraulic release. There is
cemented liner from TD to 3319’. The 7-5/8” shoe is at 2925’. We will lay in cement from the TOF to the shoe
then sidetrack off the cement plug and redrill the well.
Regards,
Sean
________________________________
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.
________________________________
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 233-23T
JBR 10/14/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
HCR choke FP-cycle/grease for a pass. Test time refelcts when I was on location.
Test Results
TEST DATA
Rig Rep:Van Evera/TrickOperator:Hilcorp Alaska, LLC Operator Rep:Pederson/Moore
Rig Owner/Rig No.:Hilcorp 147 PTD#:2240880 DATE:8/3/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM240806181947
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 4
MASP:
2441
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
13 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"P
#1 Rams 1 2-7/8"x5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 2-1/16"&3-1/FP
Kill Line Valves 3 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1700
200 PSI Attained P26
Full Pressure Attained P89
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2612
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P16
#1 Rams P4
#2 Rams P4
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9
9999
9
9
FP
HCR choke FP
2240880
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Beluga River Unit, Sterling-Beluga Gas Pool, BRU 233-23T
Hilcorp Alaska, LLC
Permit to Drill Number: 224-088
Surface Location: 504' FSL, 2546' FWL, Sec 23, T13N, R10W, SM, AK
Bottomhole Location: 1456' FSL, 1516' FEL, Sec 23, T13N, R10W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this day of July 2024. 22
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.07.22 19:42:35 -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: 7,106' TVD: 6,844'
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): 93.8 15. Distance to Nearest Well Open
Surface: x-320560 y-2630904 Zone-4 75.3 to Same Pool:1180' to BRU 224-23T
16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 56 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 GBCD 2,936' Surface Surface 2,936' 2,738'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,320' 2,786' 2,606' 7,106' 6,844'
Tieback 3-1/2" 9.2# L-80 EUE 2,786' Surface Surface 2,786' 2,606
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
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
8/1/2024
4948' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
Tieback Assy.
2449
Drilling Manager
Monty Myers
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
Intermediate
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 980 ft3 / T - 128 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
18. Casing Program:Top - Setting Depth - BottomSpecifications
3125
GL / BF Elevation above MSL (ft):
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 971 ft3 / T - 131 ft3
2441
1192' FSL, 1870' FEL, Sec 23, T13N, R10W, SM, AK
1456' FSL, 1516' FEL, Sec 23, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
504' FSL, 2546' FWL, Sec 23, T13N, R10W, SM, AK ADL 21127, ADL 17658, ADL 21128
BRU 233-23T
Beluga River Unit
Sterling-Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
Drilling Manager
06/26/24
Monty M
Myers
By Grace Christianson at 10:47 am, Jun 27, 2024
A.Dewhurst 11JUL24
50-283-20200-00-00
Submit FIT/LOT results within 48 hrs of performing test.
224-088
DSR-7/8/24
BOP test to 3000 psi. Annular test to 2500 psi.
BJM 7/22/24*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.07.22 19:42:50 -08'00'07/22/24
RBDMS JSB 072324
BRU 233-23T
PTD Program
Beluga River Unit
June 18, 2024
BRU 233-23T
Drilling Procedure
Contents
1.0 Well Summary................................................................................................................................2
2.0 Management of Change Information...........................................................................................3
3.0 Tubular Program:..........................................................................................................................4
4.0 Drill Pipe Information:..................................................................................................................4
5.0 Internal Reporting Requirements................................................................................................5
6.0 Planned Wellbore Schematic........................................................................................................6
7.0 Drilling / Completion Summary...................................................................................................7
8.0 Mandatory Regulatory Compliance / Notifications....................................................................8
9.0 R/U and Preparatory Work........................................................................................................10
10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11
11.0 Drill 9-7/8” Hole Section..............................................................................................................12
12.0 Run 7-5/8” Surface Casing..........................................................................................................14
13.0 Cement 7-5/8” Surface Casing....................................................................................................16
14.0 BOP N/U and Test........................................................................................................................19
15.0 Drill 6-3/4” Hole Section..............................................................................................................20
16.0 Run 3-1/2” Production Liner......................................................................................................22
17.0 Cement 3-1/2” Production Liner................................................................................................25
18.0 3-1/2” Liner Tieback Polish Run................................................................................................29
19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................30
20.0 Diverter Schematic ......................................................................................................................31
21.0 BOP Schematic.............................................................................................................................32
22.0 Wellhead Schematic.....................................................................................................................33
23.0 Anticipated Drilling Hazards......................................................................................................34
24.0 Hilcorp Rig 147 Layout...............................................................................................................36
25.0 FIT/LOT Procedure ....................................................................................................................37
26.0 Choke Manifold Schematic.........................................................................................................38
27.0 Casing Design Information.........................................................................................................39
28.0 6-3/4” Hole Section MASP..........................................................................................................40
29.0 Spider Plot w/ 660’ Radius for SSSV.........................................................................................41
30.0 Surface Plat As-Built...................................................................................................................42
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1.0 Well Summary
Well BRU 233-23T
Pad & Old Well Designation BRU J Pad – Grassroots Well
Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7106 MD / 6844’ TVD
PBTD, MD / TVD 7006’ MD
AFE Number
AFE Drilling Days
AFE Drilling Amount
Maximum Anticipated Pressure
(Surface)2441 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3125 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB 93.80’
Ground Elevation 75.30’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 -
Surface
9-7/8”7-5/8”6.875”6.750”8.500”29.7 P110/
L-80
GBCD 6890 4790 683
Prod
6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
** Liner must overlap surface casing by at least 100’.
*Test surface casing to L-80 specifications
4.0 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
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellView.
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.
5.2 Afternoon Updates
x Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
x Submit a short operations update each morning by 7am in NDE – Drilling Comments
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills:
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com
5.6 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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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
BRU 233-23T is an S-shaped directional grassroots development well to be drilled from BRU J Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Sterling and Beluga sands.
The base plan is an S-shaped directional wellbore with a kickoff point at ~250’ MD. Maximum hole angle
will be ~26 deg. and TD of the well will be 7106’ TMD/ 6844’ TVD, ending with 6 deg inclination left in
the hole. Vertical separation will be 1543 ft.
Drilling operations are expected to commence approximately August, 2024. The Hilcorp Rig # 147 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 2936’ MD / 2738’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine
TOC. Necessary remedial action will then be discussed with AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste
Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial
reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 147 to wellsite
2. N/U diverter and test.
3. Drill 9-7/8” hole to 2936’ MD. Run and cmt 7-5/8” surface casing.
4. Test casing to 3500 psi. Perform 14.0# FIT
5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi
6. Drill 6-3/4” hole section to 7106’ MD. Perform Wiper trip.
7. Run and cmt 3-1/2” production liner.
8. Displace well to 6% KCL completion fluid.
9. POOH and LDDP.
10. RIH and land 3-1/2” tieback string in liner top.
11. Test IA to 3000; Test tubing to 3000 psi
12. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo
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8.0 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 of BRU 233-23T. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/10 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.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office.
x Review all conditions of approval of the AOGCC 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.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 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: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
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 testing BOPs.
x Any other notifications required in APD.
Additional requirements may be stipulated on APD and Sundry.
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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 / Email:bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
9.0 R/U and Preparatory Work
9.1 Set 16” conductor at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install landing ring on conductor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.8 Mix mud for 9-7/8” hole section.
9.9 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” 2M Diverter
10.1 N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE:Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
10.5 Estimated Diverter line orientation on BRU J Pad:
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11.0 Drill 9-7/8” Hole Section
11.1 P/U 9-7/8” directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8” hole section to 2936’ MD/ 2738’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Inlet experience to drill through coal seams efficiently.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x TD the hole section in a good shale
x Take MWD surveys every stand drilled (60’ intervals).
11.5 9-7/8” hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-2936’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Parker 7-5/8” casing running equipment.
x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 7-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 7-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead
& tail, TOC brought to surface.
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Estimated Total Cement Volume:
Cement Slurry Design:
Lead Slurry (2436’ MD to surface)Tail Slurry (2936’ to 2436’ MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.44 ft3/sk 1.16 ft3/sk
Mixed Water 14.40 gal/sk 5.03 gal/sk
Mixed Fluid 14.40 gal/sk 5.03 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
CalSeal Accelerator D-Air 5000 Anti Foam
VersaSet Thixotropic Calcium Chloride Accelerator
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner
BridgeMaker II Lost Circulation
Verified cement calcs -bjm
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13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 – 18 hours after CIP.
x Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is
1.5”.
13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.14 R/D cement equipment. Flush out wellhead with FW.
13.15 Back out and L/D landing joint. Flush out wellhead with FW.
13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.17 Lay down landing joint and pack-off running tool.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
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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
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test
Packoff to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Land out test plug (if not installed previously).
x Test BOP to 250/3000 psi for 5/10 min.
x Test VBR’s with 3-1/2” and 4-1/2” test joints
x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint
x Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
2936’- 7106’9.0 – 9.7 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation:6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 – 9.7 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
x Triple Combo LWD tools required (DEN, POR, RES)
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi
(casing will be a combination of P110 and L80).
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 14.0 ppg EMW. A 13.6# ppg FIT will result in a 25 bbl KTV.
15.14 Drill 6-3/4” hole section to 7106’ MD / 6844’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x Trip back to the 7-5/8” shoe about ½ way through the hole section
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Lost circulation potential when drilling through Beluga D and E. SLOW ROP, Add
Black products and background LCM to the mud.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
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15.17 LD BHA
15.18 RIH to TD, pump sweep, CBU and condition mud for casing run.
15.19 POOH LDDP and BHA
15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint.
16.0 Run 3-1/2” Production Liner
16.1. R/U Parker 3-1/2” casing running equipment.
x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted 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.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. 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 (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2” production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 3-1/2” production liner
Page 23 Version PTD June 18, 2024
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Page 24 Version PTD June 18, 2024
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Drilling Procedure
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16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 3-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom.
Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the
shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and
thinners.
16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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17.0 Cement 3-1/2” Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
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Estimated Total Cement Volume:
Cement Slurry Design:
Lead Slurry (6606’ MD to 2736’ MD)Tail Slurry (7106’ to 6606’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.46 ft3/sk 1.22 ft3/sk
Mixed Water 14.349 gal/sk 5.507 gal/sk
Mixed Fluid 14.469 gal/sk 5.507 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
Halad-344 Fluid Loss Halad-344 Fluid Loss
HR-5 Retarder HR-5 Retarder
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner
SA-1015 Suspension Agent
BridgeMaker II Lost Circulation
Verified cement calcs. -bjm
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17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP
entering into liner.
17.9. 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.
17.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. 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).
17.18. 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.
17.19. 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. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
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Backup release from liner hanger:
17.21. 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.
17.22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
17.23. 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.
17.24. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes.
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Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 3-1/2” Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, and LDDP and polish mill.
18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes
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19.0 3-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked
up per tally.
x Install chemical injection mandrel at ~1,500’ MD.
19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
19.3 Circulate inhibited completion fluid.
19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.48 hr notice required.
19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.48 hr notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO Hilcorp Rig #147
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20.0 Diverter Schematic
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Drilling Procedure
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21.0 BOP Schematic
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Drilling Procedure
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22.0 Wellhead Schematic
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23.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous 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/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 – 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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Drilling Procedure
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
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.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 36 Version PTD June 18, 2024
BRU 233-23T
Drilling Procedure
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24.0 Hilcorp Rig 147 Layout
Page 37 Version PTD June 18, 2024
BRU 233-23T
Drilling Procedure
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25.0 FIT/LOT 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 with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
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 38 Version PTD June 18, 2024
BRU 233-23T
Drilling Procedure
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26.0 Choke Manifold Schematic
Page 39 Version PTD June 18, 2024
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Drilling Procedure
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27.0 Casing Design Information
Page 40 Version PTD June 18, 2024
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Drilling Procedure
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28.0 6-3/4” Hole Section MASP
Page 41 Version PTD June 18, 2024
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Drilling Procedure
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29.0 Spider Plot w/ 660’ Radius for SSSV
Page 42 Version PTD June 18, 2024
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Drilling Procedure
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30.0 Surface Plat As-Built
!""#
$
%
0
475
950
1425
1900
2375
2850
3325
3800
4275
4750
5225
5700
6175
6650
7125True Vertical Depth (950 usft/in)0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650
Vertical Section at 52.20° (950 usft/in)
BRU 233-23T wp02 tgt1
7 5/8" x 9 7/8"
3 1/2" x 6 3/4"
5 0 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 00 0
4 50 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 1 0 6
BRU 233-23T wp03
Start Dir 2.5º/100' : 250' MD, 250'TVD
Start Dir 3º/100' : 650' MD, 647.97'TVD
End Dir : 1379.84' MD, 1337.26' TVD
Start Dir 2º/100' : 2966.09' MD, 2764.58'TVD
End Dir : 3960.27' MD, 3715.8' TVD
Total Depth : 7105.5' MD, 6843.8' TVD
Sterling_A1
Sterling_B
Sterling_C
Beluga_D
Beluga_E
Beluga_F
Beluga_G
Beluga_H
Beluga_I
Beluga_J
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: BRU 233-23T
75.30
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2630904.82 320560.15 61° 11' 49.6525 N 151° 1' 2.0201 W
SURVEY PROGRAM
Date: 2024-06-13T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2936.00 BRU 233-23T wp03 (BRU 233-23T) 3_MWD+AX+Sag
2936.00 7105.50 BRU 233-23T wp03 (BRU 233-23T) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3210.80 3117.00 3444.87 Sterling_A1
3366.80 3273.00 3606.16 Sterling_B
3513.80 3420.00 3756.23 Sterling_C
3730.80 3637.00 3975.35 Beluga_D
3954.80 3861.00 4200.59 Beluga_E
4295.80 4202.00 4543.47 Beluga_F
4749.80 4656.00 4999.97 Beluga_G
5079.80 4986.00 5331.79 Beluga_H
5783.80 5690.00 6039.66 Beluga_I
6334.80 6241.00 6593.70 Beluga_J
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: BRU 233-23T, True North
Vertical (TVD) Reference:RKB As-Built @ 93.80usft (147)
Measured Depth Reference:RKB As-Built @ 93.80usft (147)
Calculation Method:Minimum Curvature
Project:Beluga River
Site:BRU J-Pad
Well:Plan: BRU 233-23T
Wellbore:BRU 233-23T
Design:BRU 233-23T wp03
CASING DETAILS
TVD TVDSS MD Size Name
2737.80 2644.00 2936.33 7-5/8 7 5/8" x 9 7/8"
6843.80 6750.00 7105.50 3-1/2 3 1/2" x 6 3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2.5º/100' : 250' MD, 250'TVD
3 650.00 10.00 25.00 647.97 31.56 14.71 2.50 25.00 30.97 Start Dir 3º/100' : 650' MD, 647.97'TVD
4 916.67 18.00 25.00 906.51 89.98 41.96 3.00 0.00 88.30
5 1379.84 25.87 56.49 1337.26 211.22 157.01 3.00 71.61 253.52 End Dir : 1379.84' MD, 1337.26' TVD
6 2966.09 25.87 56.49 2764.58 593.30 734.02 0.00 0.00 943.63 Start Dir 2º/100' : 2966.09' MD, 2764.58'TVD
7 3960.27 6.00 52.71 3715.80 746.06 958.44 2.00 -178.84 1214.58 BRU 233-23T wp02 tgt1 End Dir : 3960.27' MD, 3715.8' TVD
8 7105.50 6.00 52.71 6843.80 945.24 1220.00 0.00 0.00 1543.33 Total Depth : 7105.5' MD, 6843.8' TVD
075150225300375450525600675750825900975South(-)/North(+) (150 usft/in)-75 0 75 150 225 300 375 450 525 600 675 750 825 900 975 1050 1125 1200 1275West(-)/East(+) (150 usft/in)BRU 233-23T wp02 tgt17 5/8" x 9 7/8"3 1/2" x 6 3/4"25050075010001 2 5 01 5 0 0
1 7 5 0
2 0 0 0
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
3 2 5 0
3 5 0 0375040004250
45 00
4 750500 0525 05500575060006250650067506844BRU 2 33 -23 T w p 03
Start Dir 2.5º/100' : 250' MD, 250'TVDStart Dir 3º/100' : 650' MD, 647.97'TVDEnd Dir : 1379.84' MD, 1337.26' TVDStart Dir 2º/100' : 2966.09' MD, 2764.58'TVDEnd Dir : 3960.27' MD, 3715.8' TVDTotal Depth : 7105.5' MD, 6843.8' TVDCASING DETAILSTVDTVDSS MDSize Name2737.80 2644.00 2936.33 7-5/8 7 5/8" x 9 7/8"6843.80 6750.00 7105.50 3-1/2 3 1/2" x 6 3/4"Project: Beluga RiverSite: BRU J-PadWell: Plan: BRU 233-23TWellbore: BRU 233-23TPlan: BRU 233-23T wp03WELL DETAILS: Plan: BRU 233-23T75.30+N/-S +E/-WNorthingEastingLatitudeLongitude0.00 0.00 2630904.82 320560.15 61° 11' 49.6525 N 151° 1' 2.0201 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 233-23T, True NorthVertical (TVD) Reference:RKB As-Built @ 93.80usft (147)Measured Depth Reference:RKB As-Built @ 93.80usft (147)Calculation Method:Minimum Curvature
-1250125250375500625750875100011251250137515001625South(-)/North(+) (250 usft/in)-375 -250 -125 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000West(-)/East(+) (250 usft/in)BRU 233-23T wp0 tgt1250500750100012501500175 0
B R U 2 11 -2 6
2 5 0500750
1000
1250
150 0
175 0
2 0 0 0
22 5 0
250 0
27 5 0
30 0 0BRU 24425050 075010001250
150017502000225025002750300032503 5 0 0
3 7 5 040004250450047505000525055005750600062506369BRU 224-23T25050075010001250
150017502000225025002750300032503500375040004250450 0475050005250550057506000625065006750688 0BRU 224-2319BRU 221-2657506000625065006562BRU 233-23250500750100012501500BRU 232-267 5/8" x 9 7/8"3 1/2" x 6 3/4"250500750100012501 5 0 0
1 7 5 0
2 0 0 0
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
3 2 5 0
3 5 0 037504000425045004750500052505500575060006250650067506844BRU 23 3 -23T
w
p
00 Project: Beluga RiverSite: BRU J-PadWell: Plan: BRU 233-23TWellbore: BRU 233-23TPlan:BRU 233-23T wp0-2000200400South(-)/North(+) (400 usft/in)-400 -200 0 200 400West(-)/East(+) (400 usft/in)Plan: BRU 233-23TBRU 211-26BRU 244-23BRU 224-23TBRU 224-23Plan: BRU 221-26BRU 232-261000125015001750
2 0 0 0
1000
1250
150 0
2505001250
200022502501250
1750200025017501 50 0
1 7 5 0
2 0 0 0
2 2 5 0
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0.001.002.003.004.00Separation Factor0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400Measured Depth (1200 usft/in)BRU 224-23TBRU 233-23BRU 232-26No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: Plan: BRU 233-23T NAD 1927 (NADCON CONUS) Alaska Zone 0475.30+N/-S+E/-W NorthingEastingLatitudeLongitude0.00 0.002630904.82 320560.15 61° 11' 49.6525 N 151° 1' 2.0201 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: BRU 233-23T, True NorthVertical (TVD) Reference: RKB As-Built @ 93.80usft (147)Measured Depth Reference:RKB As-Built @ 93.80usft (147)Calculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name2737.80 2644.00 2936.33 7-5/8 7 5/8" x 9 7/8"6843.80 6750.00 7105.50 3-1/2 3 1/2" x 6 3/4"SURVEY PROGRAMDate: 2024-06-13T00:00:00 Validated: Yes Version: Depth FromDepth To Survey/PlanTool18.50 2936.00 BRU 233-23T wp03 (BRU 233-23T)3_MWD+AX+Sag2936.00 7105.50 BRU 233-23T wp03 (BRU 233-23T) 3_MWD+AX+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400Measured Depth (1200 usft/in)BRU 211-26BRU 244-23BRU 224-23TBRU 224-23TBRU 224-23GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 7105.50Project: Beluga RiverSite: BRU J-PadWell: Plan: BRU 233-23TWellbore: BRU 233-23TPlan: BRU 233-23T wp03Ladder/S.F. Plots
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.
BELUGA RIVER
BRU 233-23T
224-088
STERLING-BELUGA GAS
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 233-23TInitial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240880BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes ADL21127, ADL17658, and ADL211282 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by CO 8024 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) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2441, BOP rated to 5k, (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Max anticipated pore pressure of 8.8 ppg EMW at TD, however many severely under-pressured sands expected36 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]ApprADDDate7/11/2024ApprBJMDate7/22/2024ApprADDDate7/11/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 7/22/2024
