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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: 09/12/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250912
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 223-34T 50283202060000 225059 8/28/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/19/2025 AK E-LINE CIBP
BRU 224-34T 50283202050000 225044 8/17/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/22/2025 AK E-LINE Perf
BRU 224-34T 50283202050000 225044 8/27/2025 AK E-LINE Perf
BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf
GP 11-13RD 50733200260100 191133 8/29/2025 AK E-LINE Perf
KALOTSA 6 50133206850000 219114 8/14/2025 AK E-LINE PPROF
MGS ST 17595 06 50733100730000 166003 8/19/2025 AK E-LINE Drift
MGS ST 17595 06 50733100730000 166003 8/26/2025 AK E-LINE Drift
MGS ST 17595 11 50733200130000 167017 8/17/2025 AK E-LINE CBL
MGS ST 17595 20 50733203770000 185135 8/21/2025 AK E-LINE CBL
MPI 1-61 50029225200000 194142 8/19/2025 AK E-LINE Patch
NCIU A-21A 50883201990100 225075 8/23/2025 AK E-LINE Perf
END 1-23 50029225100000 194128 7/14/2025 HALLIBURTON MFC40
END 2-74 50029237850000 224024 7/12/2025 HALLIBURTON MFC40
END 3-07A 50029219110100 198147 7/13/2005 HALLIBURTON COILFLAG
END 3-15 50029217510000 187094 7/15/2025 HALLIBURTON MFC24
NS-20 50029231180000 202188 9/2/2025 HALLIBURTON COILFLAG
PBU 01-13A 50029202700100 225052 8/18/2025 HALLIBURTON RBT-COILFLAG
PBU 07-24A 50029209450100 225045 8/3/2025 HALLIBURTON RBT-COILFLAG
PBU C-34C 50029217850300 225068 8/25/2025 HALLIBURTON RBT
SD-07 50133205940000 211050 8/14/2025 HALLIBURTON TMD3D
ODSK-14 50703206100000 209155 9/8/2025 READ CaliperSurvey
Please include current contact information if different from above.
T40874
T40875
T40875
T40875
T40875
T40876
T40877
T40878
T40879
T40879
T40880
T40881
T40882
T40883
T40884
T40885
T40886
T40887
T40888
T40889
T40890
T40891
T40892
T40893
BRU 241-23 50283201910000 223061 8/20/2025 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.09.12 14:33:03 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 08/07/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250807
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 23 50133206350000 214093 6/26/2025 AK E-LINE PPROF
T40741
BCU 25 50133206440000 214132 7/16/2025 AK E-LINE Plug/Cement
T40742
BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf
T40743
BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF
T40743
BRU 213-26 50283201920000 223069 7/7/2025 AK E-LINE Perf
T40744
BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf
T40745
BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf
T40745
BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf
T40745
BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf
T40746
GP 11-13RD 50733200260100 191133 6/2/2025 AK E-LINE PPFROF
T40747
KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF
T40748
MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper
T40749
MPU F-21 50029226940000 196135 7/10/2025 AK E-LINE Caliper
T40750
MPU G-02 50029219260000 189028 7/6/2025 AK E-LINE Puncher
T40751
MPU I-01 50029220650000 190090 7/7/2025 AK E-LINE TubingPunch
T40752
NS-19 50029231220000 202207 6/27/2025 AK E-LINE Perf
T40753
PBU J-07C 50029202410300 225026 5/29/2025 BAKER MRPM
T40754
PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM
T40755
PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf
T40756
TBU D-07RD2 50733201170200 192155 7/19/2025 AK E-LINE Perf
T40757
TBU M-09 50733204760000 196127 7/18/2025 AK E-LINE Perf
T40758
Please include current contact information if different from above.
T40746BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.08.08 11:16:55 -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: 7/15/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250715
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF
BCU 14B 50133205390200 222057 6/20/2025 AK E-LINE Perf
BR 03-87 50733204370000 166052 6/15/2025 AK E-LINE Perf
BRU 211-35 50283201890000 223050 6/2/2025 AK E-LINE Perf
BRU 213-26 50283201920000 223069 6/23/2025 AK E-LINE Perf
BRU 221-24 50283202020000 225027 6/4/2025 AK E-LINE Perf
BRU 221-24 50283202020000 225027 6/22/2025 AK E-LINE Perf
BRU 221-24 50283202020000 225027 6/12/2025 AK E-LINE PPROF
BRU 241-23 50283201910000 223061 6/10/2025 AK E-LINE Cement/Perf
BRU 241-23 50283201910000 223061 6/19/2025 AK E-LINE CIBP
BRU 241-23 50283201910000 223061 6/21/2025 AK E-LINE Perf
BRU 241-23 50283201910000 223061 6/4/2025 AK E-LINE PlugPerf
KBU 43-07Y 50133206250000 214019 6/17/2025 AK E-LINE Perf
KU 41-08 50133207170000 224005 6/24/2025 AK E-LINE Plug Perf
LIS L5-26 50029220790000 190110 6/21/2025 AK E-LINE Patch
MRU M-25 50733203910000 187086 6/17/2025 AK E-LINE CIBP
PBU 15-14A 50029206820100 204222 6/3/2025 BAKER SPN
PBU 18-15C 50029217550300 211172 6/12/2025 AK E-LINE CBL/Perf
PBU F-38B 50029220930300 225029 6/12/2025 BAKER MRPM
SRU 241-33B 50133206960000 221053 5/25/2025 AK E-LINE CIBP
Please include current contact information if different from above.
T40659
T40660
T40661
T40662
T40663
T40664
T40664
T40664
T40665
T40665
T40665
T40665
T40666
T40667
T40668
T40669
T40670
T40671
T40672
T40673
BRU 241-23 50283201910000 223061 6/10/2025 AK E-LINE Cement/Perf
BRU 241-23 50283201910000 223061 6/19/2025 AK E-LINE CIBP
BRU 241-23 50283201910000 223061 6/21/2025 AK E-LINE Perf
BRU 241-23 50283201910000 223061 6/4/2025 AK E-LINE PlugPerf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.07.16 10:52:24 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/15/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250515
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf
T40412
END 2-72 50029237810000 224016 4/4/2025 READ CoilFlag
T40413
IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf
T40414
IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf
T40414
KU 33-08 50133207180000 224008 4/22/2025 AK E-LINE PPROF
T40415
MRU D-16RD 50733201830100 180110 4/21/2025 AK E-LINE Cement/Perf
T40416
NSU NS-06 50029230880000 202101 4/21/2025 AK E-LINE PPROF
T40417
NSU NS-19 50029231220000 202207 4/27/2025 AK E-LINE Perf
T40418
NSU NS-20 50029231180000 202188 4/24/2025 AK E-LINE Perf
T40419
NSU NS-23 50029231460000 203050 4/23/2024 AK E-LINE Packer
T40420
PBU 02-10B 50029201630200 200064 3/21/2025 BAKER SPN
T40421
PBU 06-19B 50029207910200 224095 3/1/2025 BAKER MRPM Borax
T40422
PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax
T40423
PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile
T40424
SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf
T40425
Revision Explanation: Processing report added
Please include current contact information if different from above.
T40412BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.16 08:15:21 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/22/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#2025022
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL
BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf
BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP
BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf
MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL
MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL
MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut
NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf
NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf
PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile
HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL
HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40328
T40329
T40330
T40331
T40332
T40333
T40334
T40335
T40336
T40337
T40338
T40339
BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.28 08:42:09 -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 241-23 (PTD# 223-061) Sundry # 324-659 Coil cleanout addition
Date:Thursday, April 3, 2025 2:20:00 PM
Chad,
Hilcorp has approval to add this CT contingency to the existing sundry 324-659 as described in
your email below with the following contingencies:
1. CT BOP test to 3000 psi
2. Supply Standard Nitrogen operations safety procedures to the crew before using N2.
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: Thursday, April 3, 2025 12:49 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 241-23 (PTD# 223-061) Sundry # 324-659 Coil cleanout addition
Bryan,
As we discussed yesterday on the phone we have an approved Sundry (# 324-659) that we are
planning to start perforating on. When I wrote the sundry in November we were planning the
work without coil or N2 for push back if necessary (because of being on the west side). We are
going to test each sand individually until we find gas. I would like to be prepared in the event
we bring in sand during one of these tests that we can move quickly to using coil for a
cleanout.
We are requesting to add the following contingency steps to the Sundry 324-659 for a coil
cleanout on this project.
Contingency (If fill is above perfs & unable to push fluid away with N2):
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. Eline to set plug over wet or sandy perfs
5. 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
6. RDMO coil tubing
7. Continue perforating well.
Attached is the Coil BOP schematic
Please let me know if we have approval for contingency coil work.
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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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 241-23 50283201910000 223061 11/8/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.05 14:52:46 -09'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 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):
7,515'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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
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:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade: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
ADL0021128
223-061
50-283-20191-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
2,849'
8,430psi
2,799'
Size
120'
3,049'
MD
See Attached Schematic
2,980psi
6,890psi
120'120'
3,049'
December 10, 2024
Tieback
7,513'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 241-23CO 802A
Same
7,159'4-1/2"
~1301psi
4,672'
See Schematic
Length
LTP; N/A 2,846' MD/ 2,533' TVD; N/A, N/A
7,161'4,499'4,189'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:22 pm, Nov 20, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.11.20 15:10:36 -
09'00'
Noel Nocas
(4361)
324-659
A.Dewhurst 25NOV24 DSR-11/21/24BJM 11/26/24
10-404
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.11.26 15:24:30 -09'00'11/26/24
RBDMS JSB 112924
Well Prognosis
Change of Program
Well Name: BRU 241-23 API Number: 50-283-20191-00-00
Current Status: SI Gas Producer Permit to Drill Number: 223-061
First Call Engineer: Chad Helgeson (907) 229-4824 (C)
Second Call Engineer: Scott Warner (907) 830-8863
Maximum Expected BHP: 1684 psi @ 3828’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 1301 psi (Based on 0.1 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.70 psi/ft using 13.6 ppg EMW FIT at the surface casing shoe 12/19/23
Shallowest Potential Perf TVD: MPSP/(0.70-0.1) = 1301 psi / 0.6 = 2168‘ TVD
Top of Pools per CO 802A: Sterling Beluga Gas Pool: 3580’ MD, 3287' TVD
Well Status: SI Gas Well
Brief Well Summary:
BRU 241-23 is a 2023 grass roots well, originally brought online in the Beluga E6 sand at over 2MM. A coil
cleanout and new perforations were added on Sundry # 324-543 and the zones brought in water. The purpose
of this change of program is to add more perforations in the well that were not originally in the sundry. All
sands lie in the Sterling Beluga Gas Pool.
Procedure:
1. MIRU EL
2. PT lubricator to 250 psi low/2,000 psi high
3. Perforate and test the below Sterling sands from the bottom up:
Sand MD Top MD Base TVD Top TVD Base H
Top Sterling Beluga Pool 3580’ 3287’
Sterling A1 ±3,600' ±3,607' ±3,306' ±3,313' ±7'
Sterling A2 ±3,610' ±3,612' ±3,316' ±3,317' ±2'
Sterling A3 ±3,637' ±3,643' ±3,342' ±3,348' ±6'
Sterling A4B ±3,675' ±3,731' ±3,378' ±3,433' ±56'
Sterling B3 ±3,879' ±3,892' ±3,577' ±3,590' ±13'
Sterling B4 ±3,903' ±3,915' ±3,601' ±3,613' ±12'
Sterling C1 Upper ±3,935' ±3,941' ±3,632' ±3,638' ±6'
Sterling C1 Lower ±3,948' ±3,965' ±3,645' ±3,662' ±17'
Sterling C2 ±3,981' ±3,998' ±3,678' ±3,694' ±17'
Sterling C3 ±4,020' ±4,029' ±3,716' ±3,725' ±9'
Sterling C4 Upper ±4,041' ±4,045' ±3,737' ±3,740' ±4'
Sterling C4 Lower ±4,058' ±4,076' ±3,753' ±3,771' ±18'
Sterling C5 ±4,120' ±4,134' ±3,814' ±3,828' ±14'
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
c. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
Perfs not allowed above surface csg
shoe. -bjm
Well Prognosis
Change of Program
setting a plug above perforations
4. RDMO
5. Turn well over to production & flow test well
Attachments:
1. Proposed Well Schematic #2
Updated by CAH 11-20-24
PROPOSED #2
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
RKB to GL = 18.5’
PERFORATION DETAIL- Cont on pg 2
PERFORATION DETAIL- cont. on pg. 2
Sands Top MD Btm MD Top TVD Btm TVD Date Status
Top Of Pool: 3580’ MD & 3287’ TVD
A1 ±3,600' ±3,607' ±3,306' ±3,313' TBD Proposed
A2 ±3,610' ±3,612' ±3,316' ±3,317' TBD Proposed
A3 ±3,637' ±3,643' ±3,342' ±3,348' TBD Proposed
A4B ±3,675' ±3,731' ±3,378' ±3,433' TBD Proposed
B3 ±3,879' ±3,892' ±3,577' ±3,590' TBD Proposed
B4 ±3,903' ±3,915' ±3,601' ±3,613' TBD Proposed
C1 Upper ±3,935' ±3,941' ±3,632' ±3,638' TBD Proposed
C1 Lower ±3,948' ±3,965' ±3,645' ±3,662' TBD Proposed
C2 ±3,981' ±3,998' ±3,678' ±3,694' TBD Proposed
C3 ±4,020' ±4,029' ±3,716' ±3,725' TBD Proposed
C4 Upper ±4,041' ±4,045' ±3,737' ±3,740' TBD Proposed
C4 Lower ±4,058' ±4,076' ±3,753' ±3,771' TBD Proposed
C5 ±4,120' ±4,134' ±3,814' ±3,828' TBD Proposed
D1 4,159' 4,163' 3,853' 3,857' 11/8/24 Isolated
D3-U 4,196' 4,202' 3,889' 3,895' 11/8/24 Isolated
D3 4,209' 4,224' 3,902' 3,917' 11/8/24 Isolated
D5 4,264’ 4,274’ 3,957’ 3,966’ 4/5/24 Isolated
D5 4,264’ 4,274’ 3,957’ 3,966’ 5/17/24 Isolated
D6-U 4,297' 4,300' 3,989' 3,992' 10/17/24 Isolated
D6 4,304' 4,322' 3,996' 4,014' 10/17/24 Isolated
E2 4,443' 4,447' 4,133' 4,137' 10/17/24 Isolated
E3 4,460' 4,463' 4,150' 4,153' 10/17/24 Isolated
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) 12.0 ppg lead, 173 sx (33 bbls) 15.8 ppg tail, returned all spacer and
87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) 12 ppg lead, 99sks (22 bbls) 15.3 ppg tail cement. Bumped plug
and circulated 50 bbls of cement off liner top. TOC @ 2850’ (9-27-23 CBL)
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,841’ 7,513’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,849’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,506’ 3.958” 4.780” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 4,154’ 3.958” CIBP (3.71” OD Set 11/8/24
4 4,524’ - 3.958” CIBP (3.71” OD) Set 05-15-24 w/25’ cmt; TOC @ 4,499’
5 5,000’ - 3.958” CIBP (3.71” OD) Set 10-21-23
6 6,070’ - 3.958” CIBP (3.71” OD) Set 10-05-23
7 6,204’ - 3.958” CIBP (3.71” OD) Set 10-05-23
8 6,595’ - 3.958” CIBP (3.71” OD) Set 10-02-23
6-3/4”
hole
2
1
5
6
7
8
4
3
Updated by CAH 11-20-24
PROPOSED #2
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PERFORATION DETAIL- Cont from pg 1
E5 4,569’ 4,577’ 4,258’ 4,266’ 4/5/24 Isolated
E6 4,603’ 4,609’ 4,291’ 4,297’ 11/25/23 Isolated
E6 4,616’ 4,620’ 4,304’ 4,308’ 11/25/23 Isolated
E6 4,685’ 4,690’ 4,371’ 4,376’ 10/22/23 Isolated
F7 5,024' 5,052' 4,706' 4,734' 10/12/23 Isolated
F10 5,076' 5,081' 4,758' 4,763' 10/12/23 Isolated
F10 5,105' 5,109' 4,786' 4,790' 10/12/23 Isolated
F10 5,116' 5,119' 4,797' 4,800' 10/12/23 Isolated
F10 5,124' 5,129' 4,805' 4,810' 10/12/23 Isolated
G1 5,153' 5,161' 4,834' 4,842' 10/11/23 Isolated
G2 5,197' 5,200' 4,877' 4,880' 10/11/23 Isolated
G2 5,214' 5,219' 4,894' 4,899' 10/11/23 Isolated
G5 5,286' 5,292' 4,965' 4,971' 10/10/23 Isolated
G9 5,405' 5,407' 5,082' 5,084' 10/10/23 Isolated
H 5,467' 5,469' 5,143' 5,145' 10/10/23 Isolated
H 5,481' 5,483' 5,157' 5,159' 10/10/23 Isolated
H 5,489' 5,495' 5,165' 5,171' 10/6/2023 Isolated
H2 5,534' 5,537' 5,209' 5,212' 10/6/2023 Isolated
H2 5,541' 5,547' 5,216' 5,222' 10/6/2023 Isolated
H3 5,569' 5,573' 5,244' 5,247' 10/6/2023 Isolated
H3 5,582' 5,585' 5,256' 5,259' 10/6/2023 Isolated
H5 5,666' 5,670' 5,339' 5,343' 10/6/2023 Isolated
H5 5,673' 5,676' 5,346' 5,349' 10/6/2023 Isolated
H8 5,766' 5,768' 5,437' 5,439' 10/6/2023 Isolated
H8 5,770' 5,775' 5,441' 5,446' 10/6/2023 Isolated
H8 5,781' 5,789' 5,452' 5,460' 10/6/2023 Isolated
H15 6,091' 6,111' 5,758' 5,777' 10/5/2023 Isolated
I 6,174' 6,180' 5,839' 5,845' 10/5/2023 Isolated
I1 6,219' 6,231' 5,884' 5,896' 10/3/2023 Isolated
I2 6,254' 6,268’ 5,919' 5,933' 10/3/2023 Isolated
I2 6,300' 6,304' 5,964' 5,968' 10/3/2023 Isolated
I3 6,318' 6,324' 5,982' 5,988' 10/3/2023 Isolated
I6 6,418' 6,438' 6,080' 6,100' 10/3/2023 Isolated
I11 6,620' 6,626' 6,279' 6,285' 10/1/2023 Isolated
J2 6,881' 6,905' 6,535' 6,559' 10/1/2023 Isolated
J5 7,174' 7,185' 6,824' 6,835' 10/1/2023 Isolated
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 241-23 50283201910000 223061 10/12/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.01 13:27:33 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson
Cc:Donna Ambruz
Subject:RE: BRU 241-23 (PTD# 223-061) Sundry # 324-543 Additional perf interval
Date:Thursday, October 17, 2024 3:31:00 PM
Chad,
This additional perf interval is now authorized under sundry 324-543.
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: Thursday, October 17, 2024 1:40 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 241-23 (PTD# 223-061) Sundry # 324-543 Additional perf interval
Bryan,
We identified one more sand we would like to perforate in the BRU 241-23 well on current
open sundry #324-543.
We would like to add the Beluga E 1 sand. This sand is between approved sands in this sundry.
Sand Top (MD)Btm (MD)Ft
Beluga E1 4386’4393’7’
Please let me know if you need anything else from me for this proposed perf.
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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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: CTCO, 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):
7,515'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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
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:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade: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
ADL0021128
223-061
50-283-20191-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
2,849'
8,430psi
2,799'
Size
120'
3,049'
MD
See Attached Schematic
2,980psi
6,890psi
120'120'
3,049'
October 4, 2024
Tieback
7,513'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 241-23CO 802
Same
7,159'4-1/2"
~1345psi
4,672'
See Schematic
Length
LTP; N/A 2,846' MD/ 2,533' TVD; N/A, N/A
7,161'4,499'4,189'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:28 pm, Sep 20, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.09.20 14:54:06 -
08'00'
Noel Nocas
(4361)
324-543
CT BOP test to 2000 psi
X
10-404
Perforate
BJM 10/3/24 DSR-9/27/24SFD 10/7/2024JLC 10/7/2024
Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.10.07 14:28:50 -08'00'
10/07/24
RBDMS JSB 100824
Well Prognosis
Well Name: BRU 241-23 API Number: 50-283-20191-00-00
Current Status: Gas Producer Permit to Drill Number: 223-061
First Call Engineer: Chad Helgeson (907) 229-4824 (C)
Second Call Engineer: Scott Warner (907) 830-8863
Maximum Expected BHP:1741 psi @ 3957’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure:1345 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: Producing Gas Well 309 mcfd, 1.5 bwpd @ 112 psi
Brief Well Summary:
BRU 241-23 is a 2023 grass roots well, originally brought online in the Beluga E6 sand at over 2MM. The well
has gradually declined and the objective of this sundry is to increase productivity through perforating additional
sands after a coil cleanout. All sands lie in the Sterling Beluga Gas Pool.
Wellbore Conditions:
09/14/24 SL drift w/ 1.75” x 4’ DD bailer to 4284’ KB, ran pt survey. Tools covered in light grey mud
08/22/24 SL drift w/ 1.9” GR, tag at 4272’ KB- tools covered in wet fine silt
Procedure:
1. Review all approved COAs
2. MIRU CTU
3. PT BOPE to 250 psi low / 2,000 psi high
4. RIH with CT nozzle or mill, clean out as deep as possible to TOC at ~4499’
5. RIH and reverse out fluid with nitrogen, trap ~1500 psi on the wellbore for perforating
6. RDMO CT
7. MIRU EL
8. PT lubricator to 250 psi low/2,000 psi high
9. Perforate and test the below Beluga sands from the bottom up:
Sand MD Top MD Base TVD Top TVD Base H
Top Sterling Beluga Pool 3580’ 3287’
Beluga D1 ±4,159' ±4,163' ±3,853' ±3,857' ±4'
Beluga D3 Upper ±4,196' ±4,202' ±3,889' ±3,895' ±6'
Beluga D3 ±4,209' ±4,224' ±3,902' ±3,917' ±15'
Beluga D6 Upper ±4,297' ±4,300' ±3,989' ±3,992' ±3'
Beluga D6 ±4,304' ±4,322' ±3,996' ±4,014' ±18'
Beluga E2 ±4,443' ±4,447' ±4,133' ±4,137' ±4'
Beluga E3 ±4,460' ±4,463' ±4,150' ±4,153' ±3'
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 13.64 ppg EMW FIT at the surface casing shoe (0.709 psi/ft frac grad)
Well Prognosis
c. Shallowest Allowable Perf TVD = MPSP/(0.709-0.1) = 1345 psi / 0.609 = 2208‘ TVD
d. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
Note: Requesting approval to not place cement on top of any plug/plugs that may be set due to
perforation intervals being too close together to allow for it
e. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
setting a plug above perforations
10. RDMO
11. Turn well over to production & flow test well
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
, or ~2,372' MD SFD
Updated by DMA 05-22-24
SCHEMATIC
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
RKB to GL = 18.5’
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD Date Status
D5 4,264’ 4,274’ 3,957’ 3,966’ 4/5/24 Open
D5 4,264’ 4,274’ 3,957’ 3,966’ 5/17/24 Open
E5 4,569’ 4,577’ 4,258’ 4,266’ 4/5/24 Isolated
E6 4,603’ 4,609’ 4,291’ 4,297’ 11/25/23 Isolated
E6 4,616’ 4,620’ 4,304’ 4,308’ 11/25/23 Isolated
E6 4,685’ 4,690’ 4,371’ 4,376’ 10/22/23 Isolated
F7 5,024' 5,052' 4,706' 4,734' 10/12/23 Isolated
F10 5,076' 5,081' 4,758' 4,763' 10/12/23 Isolated
F10 5,105' 5,109' 4,786' 4,790' 10/12/23 Isolated
F10 5,116' 5,119' 4,797' 4,800' 10/12/23 Isolated
F10 5,124' 5,129' 4,805' 4,810' 10/12/23 Isolated
G1 5,153' 5,161' 4,834' 4,842' 10/11/23 Isolated
G2 5,197' 5,200' 4,877' 4,880' 10/11/23 Isolated
G2 5,214' 5,219' 4,894' 4,899' 10/11/23 Isolated
G5 5,286' 5,292' 4,965' 4,971' 10/10/23 Isolated
G9 5,405' 5,407' 5,082' 5,084' 10/10/23 Isolated
H 5,467' 5,469' 5,143' 5,145' 10/10/23 Isolated
H 5,481' 5,483' 5,157' 5,159' 10/10/23 Isolated
H 5,489' 5,495' 5,165' 5,171' 10/6/2023 Isolated
H2 5,534' 5,537' 5,209' 5,212' 10/6/2023 Isolated
H2 5,541' 5,547' 5,216' 5,222' 10/6/2023 Isolated
H3 5,569' 5,573' 5,244' 5,247' 10/6/2023 Isolated
H3 5,582' 5,585' 5,256' 5,259' 10/6/2023 Isolated
H5 5,666' 5,670' 5,339' 5,343' 10/6/2023 Isolated
H5 5,673' 5,676' 5,346' 5,349' 10/6/2023 Isolated
H8 5,766' 5,768' 5,437' 5,439' 10/6/2023 Isolated
H8 5,770' 5,775' 5,441' 5,446' 10/6/2023 Isolated
H8 5,781' 5,789' 5,452' 5,460' 10/6/2023 Isolated
H15 6,091' 6,111' 5,758' 5,777' 10/5/2023 Isolated
I 6,174' 6,180' 5,839' 5,845' 10/5/2023 Isolated
I1 6,219' 6,231' 5,884' 5,896' 10/3/2023 Isolated
I2 6,254' 6,268’ 5,919' 5,933' 10/3/2023 Isolated
I2 6,300' 6,304' 5,964' 5,968' 10/3/2023 Isolated
I3 6,318' 6,324' 5,982' 5,988' 10/3/2023 Isolated
I6 6,418' 6,438' 6,080' 6,100' 10/3/2023 Isolated
I11 6,620' 6,626' 6,279' 6,285' 10/1/2023 Isolated
J2 6,881' 6,905' 6,535' 6,559' 10/1/2023 Isolated
J5 7,174' 7,185' 6,824' 6,835' 10/1/2023 Isolated
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,841’ 7,513’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,849’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,506’ 3.958” 4.780” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 4,524’ - 4.500” CIBP (3.71” OD) Set 05-15-24 w/25’ cmt; TOC @ 4,499’
4 5,000’ - 4.500” CIBP (3.71” OD) Set 10-21-23
5 6,070’ - 4.500” CIBP (3.71” OD) Set 10-05-23
6 6,204’ - 4.500” CIBP (3.71” OD) Set 10-05-23
7 6,595’ - 4.500” CIBP (3.71” OD) Set 10-02-23
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) 12.0 ppg lead, 173 sx (33 bbls) 15.8 ppg tail, returned all spacer and
87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) 12 ppg lead, 99sks (22 bbls) 15.3 ppg tail cement. Bumped plug
and circulated 50 bbls of cement off liner top. TOC @ 2850’ (9-27-23 CBL)
6-3/4”
hole
2
1
4
5
6
7
3
Updated by SRW 09-20-24
PROPOSED SCHEMATIC
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
RKB to GL = 18.5’
PERFORATION DETAIL- Cont on pg 2
PERFORATION DETAIL- cont. on pg. 2
Sands Top MD Btm MD Top TVD Btm TVD Date Status
D1 ±4,159' ±4,163' ±3,853' ±3,857' TBD Proposed
D3-U ±4,196' ±4,202' ±3,889' ±3,895' TBD Proposed
D3 ±4,209' ±4,224' ±3,902' ±3,917' TBD Proposed
D5 4,264’ 4,274’ 3,957’ 3,966’ 4/5/24 Open
D5 4,264’ 4,274’ 3,957’ 3,966’ 5/17/24 Open
D6-U ±4,297' ±4,300' ±3,989' ±3,992' TBD Proposed
D6 ±4,304' ±4,322' ±3,996' ±4,014' TBD Proposed
E2 ±4,443' ±4,447' ±4,133' ±4,137' TBD Proposed
E3 ±4,460' ±4,463' ±4,150' ±4,153' TBD Proposed
E5 4,569’ 4,577’ 4,258’ 4,266’ 4/5/24 Isolated
E6 4,603’ 4,609’ 4,291’ 4,297’ 11/25/23 Isolated
E6 4,616’ 4,620’ 4,304’ 4,308’ 11/25/23 Isolated
E6 4,685’ 4,690’ 4,371’ 4,376’ 10/22/23 Isolated
F7 5,024' 5,052' 4,706' 4,734' 10/12/23 Isolated
F10 5,076' 5,081' 4,758' 4,763' 10/12/23 Isolated
F10 5,105' 5,109' 4,786' 4,790' 10/12/23 Isolated
F10 5,116' 5,119' 4,797' 4,800' 10/12/23 Isolated
F10 5,124' 5,129' 4,805' 4,810' 10/12/23 Isolated
G1 5,153' 5,161' 4,834' 4,842' 10/11/23 Isolated
G2 5,197' 5,200' 4,877' 4,880' 10/11/23 Isolated
G2 5,214' 5,219' 4,894' 4,899' 10/11/23 Isolated
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) 12.0 ppg lead, 173 sx (33 bbls) 15.8 ppg tail, returned all spacer and
87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) 12 ppg lead, 99sks (22 bbls) 15.3 ppg tail cement. Bumped plug
and circulated 50 bbls of cement off liner top. TOC @ 2850’ (9-27-23 CBL)
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,841’ 7,513’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,849’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,506’ 3.958” 4.780” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 4,524’ - 4.500” CIBP (3.71” OD) Set 05-15-24 w/25’ cmt; TOC @ 4,499’
4 5,000’ - 4.500” CIBP (3.71” OD) Set 10-21-23
5 6,070’ - 4.500” CIBP (3.71” OD) Set 10-05-23
6 6,204’ - 4.500” CIBP (3.71” OD) Set 10-05-23
7 6,595’ - 4.500” CIBP (3.71” OD) Set 10-02-23
6-3/4”
hole
2
1
4
5
6
7
3
Updated by SRW 09-20-24
PROPOSED SCHEMATIC
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PERFORATION DETAIL- Cont from pg 1
G5 5,286' 5,292' 4,965' 4,971' 10/10/23 Isolated
G9 5,405' 5,407' 5,082' 5,084' 10/10/23 Isolated
H 5,467' 5,469' 5,143' 5,145' 10/10/23 Isolated
H 5,481' 5,483' 5,157' 5,159' 10/10/23 Isolated
H 5,489' 5,495' 5,165' 5,171' 10/6/2023 Isolated
H2 5,534' 5,537' 5,209' 5,212' 10/6/2023 Isolated
H2 5,541' 5,547' 5,216' 5,222' 10/6/2023 Isolated
H3 5,569' 5,573' 5,244' 5,247' 10/6/2023 Isolated
H3 5,582' 5,585' 5,256' 5,259' 10/6/2023 Isolated
H5 5,666' 5,670' 5,339' 5,343' 10/6/2023 Isolated
H5 5,673' 5,676' 5,346' 5,349' 10/6/2023 Isolated
H8 5,766' 5,768' 5,437' 5,439' 10/6/2023 Isolated
H8 5,770' 5,775' 5,441' 5,446' 10/6/2023 Isolated
H8 5,781' 5,789' 5,452' 5,460' 10/6/2023 Isolated
H15 6,091' 6,111' 5,758' 5,777' 10/5/2023 Isolated
I 6,174' 6,180' 5,839' 5,845' 10/5/2023 Isolated
I1 6,219' 6,231' 5,884' 5,896' 10/3/2023 Isolated
I2 6,254' 6,268’ 5,919' 5,933' 10/3/2023 Isolated
I2 6,300' 6,304' 5,964' 5,968' 10/3/2023 Isolated
I3 6,318' 6,324' 5,982' 5,988' 10/3/2023 Isolated
I6 6,418' 6,438' 6,080' 6,100' 10/3/2023 Isolated
I11 6,620' 6,626' 6,279' 6,285' 10/1/2023 Isolated
J2 6,881' 6,905' 6,535' 6,559' 10/1/2023 Isolated
J5 7,174' 7,185' 6,824' 6,835' 10/1/2023 Isolated
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.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 6/21/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240621
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 5/17/2024 AK E-LINE Perf
KBU 43-07Y 50133206250000 214019 10/19/2023 AK E-LINE PLT
END 2-72 50029237810000 224016 6/10/2024 HALLIBURTON RBT
Paxton 3 50133205880000 209168 3/14/2023 AK E-LINE GPT/JBGR/RBP
PBU E-12A 50029207820100 216127 6/4/2024 HALLIBURTON RBT
PBU-GNI-03 50029228200000 197189 5/21/2024 READ CaliperSurvey
Please include current contact information if different from above.
T38984
T38985
T38986
T38987
T38988
T38989
BRU 241-23 50283201910000 223061 5/17/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.06.21 13:35:29 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/28/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240528
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 5/13/2024 AK E-LINE CIBP/Cement
HV B-12 50231200310000 207123 4/26/2024 AK E-LINE PPROF
HV B-16A 50231200400100 222070 4/24/2024 AK E-LINE PPROF
HV B-17 50231200490000 215189 4/23/2024 AK E-LINE Perf
KTU 43-6XRD2 50133203280200 205117 5/10/2024 AK E-LINE Perf
LRU C-02 50283201900000 223057 5/8/2024 AK E-LINE Perf
MPU C-11A 50029213210100 221001 2/17/2024 AK E-LINE SetPacker
NCIU A-17 50883201880000 223031 4/13/2024 AK E-LINE Plug/Perf/GPT
Please include current contact information if different from above.
T38851
T38852
T38853
T38854
T38855
T38856
T38857
T38858
BRU 241-23 50283201910000 223061 5/13/2024 AK E-LINE CIBP/Cement
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.29 09:23:53 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,515 feet See Schematic feet
true vertical 7,161 feet N/A feet
Effective Depth measured 4,499 feet 2,846 feet
true vertical 4,189 feet 2,533 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) Tieback 4-1/2" 12.6# / L-80 2,849' MD 2,624' TVD
Packers and SSSV (type, measured and true vertical depth) LTP; N/A 2,845' MD 2,533' TVD N/A, N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
Jake Flora, Operations Engineer
324-158
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
844
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
jake.flora@hilcorp.com
907-777-8442
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
120'
1 36324
0 2901
313
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-061
50-283-20191-00-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0021128
Beluga River / Sterling-Beluga Gas
Beluga River Unit (BRU) 241-23
Plugs
Junk measured
Length
Production
Liner
4,672'
Casing
Structural
7,159'7,513'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
3,049'
7,500psi
2,980psi
6,890psi
8,430psi
3,049' 2,799'
Burst Collapse
1,410psi
4,790psi
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 9:42 am, May 23, 2024
Digitally signed by Scott Warner
DN: cn=Scott Warner, c=US,
o=Hilcorp Alaska ,
email=Scott.Warner@hilcorp.com
Date: 2024.05.22 15:31:20 -08'00'
Scott
Warner
DSR-5/23/24
Page 1/1
Well Name: BRU 241-23
Report Printed: 5/22/2024www.peloton.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:4/4/2024 End Date:
Report Number
1
Report Start Date
4/4/2024
Report End Date
4/5/2024
Last 24hr Summary
MIRU AK E-Line. Unable to R/U due to leaking valve. SDFN.
Report Number
2
Report Start Date
4/5/2024
Report End Date
4/6/2024
Last 24hr Summary
MIRU AK E-Line. PT 2500 PSI. Good. W/ well flowing, perforate Beluga D5 zone 4264 to 4274. PSI 304 to 315 in 20 minutes. W/ well flowing, perforate Beluga E5
zone 4569 to 4577. PSI 338 to 378 in 20 minutes. RDMO.
Report Number
3
Report Start Date
4/12/2024
Report End Date
4/13/2024
Last 24hr Summary
SL
Report Number
4
Report Start Date
4/13/2024
Report End Date
4/14/2024
Last 24hr Summary
SL
Report Number
5
Report Start Date
4/14/2024
Report End Date
4/15/2024
Last 24hr Summary
SL
Report Number
6
Report Start Date
4/15/2024
Report End Date
4/16/2024
Last 24hr Summary
SL
Field: Beluga River
Sundry #: 324-158
State: Alaska
Rig/Service:Permit to Drill (PTD) #:223-061Permit to Drill (PTD) #:223-061
Wellbore API/UWI:50-283-20191-00-00
Page 1/1
Well Name: BRU 241-23
Report Printed: 5/22/2024www.peloton.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:4/19/2024 End Date:
Report Number
1
Report Start Date
5/11/2024
Report End Date
5/12/2024
Last 24hr Summary
Mobe crews to Beluga, to unload barge, Barge did not make it in on morning tide, unload Barge on evening tide, mobe eq. to K pad. SDFN
Report Number
2
Report Start Date
5/12/2024
Report End Date
5/13/2024
Last 24hr Summary
PJSM, PTW, Spot Eq. pull wellhouse, Close master valves, C/O swab valve. N/U BOPE, function test BOPE, good. Test BOPE, 250/3500, as per Hilcorp & AOGCC
expectations, Witness waived By Inspector Jim Regg, 1st, test, 250/4700, testing breaks on tree, close swab, remaining tests 250/3500 good. P/U injector, M/U 2
1/8" nozzle, stab on well, Test 250/3500 good. RIH washing down tag at 3664', cont wash, t/tag @ 4618'CTM, unable to work past, Wash OOH, secure well for
night, trapping 1025psi.
Report Number
3
Report Start Date
5/13/2024
Report End Date
5/14/2024
Last 24hr Summary
PTSM, PTW, R/U e-line, PT t/250/2500, good, RIH w/3.75 GR, tag @ 4578', RIH w/1 11/16" tool string tagging same depth. P/U injector, M/U coil connector Pull &
pressure test. good, M/U 2 7/8" Mud motor & 3.75 roller bit BHA. surface test good. RIH tag fill 4587' CTM, wash & ream down t/ 4618', ROP stopped, continue
working, changing paramaters, lost ability to get differential pressure, POOH, left tool string in hole. Secure well for night.
Report Number
4
Report Start Date
5/14/2024
Report End Date
5/15/2024
Last 24hr Summary
PJSM,PTW, M/U fishing BHA-Connector, check valve, jar, disconnect, xo, 3.75 overshot = 14.25', RIH latch fish @4599', POOH full recovery, P/U BHA - connector,
check valve, disconnect, circ sub, mud MTR, xo, 3.21 junk mill = 20.14', RIH tag 4617' CTM, wash & ream down t/4625', POOH secure well for night.
Report Number
5
Report Start Date
5/15/2024
Report End Date
5/16/2024
Last 24hr Summary
PJSM, Crew travel to location, Pick up injector head & lube, PIck up & make up BHA (Max OD 3.86"), Run in hole to tag @ 1506' (chemical mandril), Pull out of
hole & pick up (Max OD 3.75"), Run in hole to tag @ 4622'. Establish circulation, Clean out from 4620' to 4622'., Circulate hole clean, Pull out of hole & lay down
BHA, Rig down coil, Spot in & rig up AK Eline, Pick up lube and 3.61" x 15' patch, Pressure test to 2500 psi-good, Run in hole & tag @ 4570', Unable to set, Pull out
of the hole & pick up 3.71" CIBP, Run in hole to set @ 4524', Pull out of hole & pick up 2.5" bailer & cement, Bail 16 gal (25' in 4.5") est. TOC @ 4499', Pull out of
hole & secure well, Rig down & release Eline.
Report Number
6
Report Start Date
5/16/2024
Report End Date
5/17/2024
Last 24hr Summary
PJSM, Crew travel to location, Pick up injector head & lube, Pick up & make up wash nozzle, Pressure test to 3000 psi, Run in hole to tag @ 4458', Cool down N2
pump & unload hole recovered 92 bbls, Draw down well and monitor pressure gain, No pressure gain, Run in hole to confirm tag @ 4458', Pull out of hole & rig
down coil, Secure well.
Report Number
7
Report Start Date
5/17/2024
Report End Date
5/18/2024
Last 24hr Summary
PJSM, Crew travel to location, Spot in & rig up AK Eline, Pick up Lube and tool string GR/GPT/CCL (Max OD 3.75"), Pressure test to 2500 psi-good, Run in hole &
tag 4332', Fluid @ 3920', Pull out of hole & lay down, PIck up CCL/GR/2-3/4" Gun, Run in hole & tag @ 4279', Pick up to shooting depth & perf (D5 sand 4264'-
4274'), Pull out of hole (tools caked in mud), Rig down & release AK-eline & Fox coil.
Field: Beluga River
Sundry #: 324-158
State: Alaska
Rig/Service: Coil #8Permit to Drill (PTD) #:223-061Permit to Drill (PTD) #:223-061
Wellbore API/UWI:50-283-20191-00-00
Updated by DMA 05-22-24
SCHEMATIC
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429 / TVD = 7,075
TD = 7,515 / TVD = 7,161
RKB to GL = 18.5
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD Date Status
D5 4,264 4,274 3,957 3,966 4/5/24 Open
D5 4,264 4,274 3,957 3,966 5/17/24 Open
E5 4,569 4,577 4,258 4,266 4/5/24 Isolated
E6 4,603 4,609 4,291 4,297 11/25/23 Isolated
E6 4,616 4,620 4,304 4,308 11/25/23 Isolated
E6 4,685 4,690 4,371 4,376 10/22/23 Isolated
F7 5,024' 5,052' 4,706' 4,734' 10/12/23 Isolated
F10 5,076' 5,081' 4,758' 4,763' 10/12/23 Isolated
F10 5,105' 5,109' 4,786' 4,790' 10/12/23 Isolated
F10 5,116' 5,119' 4,797' 4,800' 10/12/23 Isolated
F10 5,124' 5,129' 4,805' 4,810' 10/12/23 Isolated
G1 5,153' 5,161' 4,834' 4,842' 10/11/23 Isolated
G2 5,197' 5,200' 4,877' 4,880' 10/11/23 Isolated
G2 5,214' 5,219' 4,894' 4,899' 10/11/23 Isolated
G5 5,286' 5,292' 4,965' 4,971' 10/10/23 Isolated
G9 5,405' 5,407' 5,082' 5,084' 10/10/23 Isolated
H 5,467' 5,469' 5,143' 5,145' 10/10/23 Isolated
H 5,481' 5,483' 5,157' 5,159' 10/10/23 Isolated
H 5,489' 5,495' 5,165' 5,171' 10/6/2023 Isolated
H2 5,534' 5,537' 5,209' 5,212' 10/6/2023 Isolated
H2 5,541' 5,547' 5,216' 5,222' 10/6/2023 Isolated
H3 5,569' 5,573' 5,244' 5,247' 10/6/2023 Isolated
H3 5,582' 5,585' 5,256' 5,259' 10/6/2023 Isolated
H5 5,666' 5,670' 5,339' 5,343' 10/6/2023 Isolated
H5 5,673' 5,676' 5,346' 5,349' 10/6/2023 Isolated
H8 5,766' 5,768' 5,437' 5,439' 10/6/2023 Isolated
H8 5,770' 5,775' 5,441' 5,446' 10/6/2023 Isolated
H8 5,781' 5,789' 5,452' 5,460' 10/6/2023 Isolated
H15 6,091' 6,111' 5,758' 5,777' 10/5/2023 Isolated
I 6,174' 6,180' 5,839' 5,845' 10/5/2023 Isolated
I1 6,219' 6,231' 5,884' 5,896' 10/3/2023 Isolated
I2 6,254' 6,268 5,919' 5,933' 10/3/2023 Isolated
I2 6,300' 6,304' 5,964' 5,968' 10/3/2023 Isolated
I3 6,318' 6,324' 5,982' 5,988' 10/3/2023 Isolated
I6 6,418' 6,438' 6,080' 6,100' 10/3/2023 Isolated
I11 6,620' 6,626' 6,279' 6,285' 10/1/2023 Isolated
J2 6,881' 6,905' 6,535' 6,559' 10/1/2023 Isolated
J5 7,174' 7,185' 6,824' 6,835' 10/1/2023 Isolated
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 TXP 6.875 Surf 3,049
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958 2,841 7,513
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958 Surf 2,849
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 1,506 3.958 4.780 Chemical Injection Sub
2 2,846 4.875 6.540 Seal Stem / Liner hanger / LTP Assembly
3 4,524 - 4.500 CIBP (3.71 OD) Set 05-15-24 w/25 cmt; TOC @ 4,499
4 5,000 - 4.500 CIBP (3.71 OD) Set 10-21-23
5 6,070 - 4.500 CIBP (3.71 OD) Set 10-05-23
6 6,204 - 4.500 CIBP (3.71 OD) Set 10-05-23
7 6,595 - 4.500 CIBP (3.71 OD) Set 10-02-23
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) 12.0 ppg lead, 173 sx (33 bbls) 15.8 ppg tail, returned all spacer and
87 bbls of cement. TOC @ Surface
4-1/2 347 sx (148 bbls) 12 ppg lead, 99sks (22 bbls) 15.3 ppg tail cement. Bumped plug
and circulated 50 bbls of cement off liner top. TOC @ 2850 (9-27-23 CBL)
6-3/4
hole
2
1
4
5
6
7
3
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:Jacob Flora
Cc:Chad Helgeson; Roby, David S (OGC); Dewhurst, Andrew D (OGC)
Subject:RE: BRU 241-23 AOGCC 10-403 324-158 PTD 223-061 - Request to add Beluga D sands to the approved sundry
Date:Monday, April 1, 2024 10:56:00 AM
Attachments:image006.png
image007.png
image008.png
image009.png
Jake,
Hilcorp has approval to add the additional perf intervals listed below. Please report this activity as part of the 10-404 for the existing
sundry 324-158.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, April 1, 2024 9:49 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>
Subject: RE: BRU 241-23 AOGCC 10-403 324-158 PTD 223-061 - Request to add Beluga D sands to the approved sundry
Good Morning Bryan,
With approval we would like to execute the below perf job later this week.
This will be my only request for the week-
Thank you,
Jake
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, March 25, 2024 1:52 PM
To: bryan.mclellan@alaska.gov; Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 241-23 AOGCC 10-403 324-158 PTD 223-061 Approved 03-20-24
Hello Bryan,
While planning to execute this approved perf add we identified a few more targets than were in the original sundry. They are
immediately above the currently approved perfs and are also in the same pool. Hilcorp requests to add the below sands:
Requesting to Add
Please let me know if you have any questions or would like to see more data.
Thanks,
Jake
Currently Approved
Approved Sundry 324-158
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Wednesday, March 20, 2024 2:06 PM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Noel Nocas <Noel.Nocas@hilcorp.com>
Subject: BRU 241-23 AOGCC 10-403 324-158 PTD 223-061 Approved 03-20-24
FYI – Please distribute as necessary.
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
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 anintended 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 havereceived 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 thismessage.
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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: 4/19/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240419
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 4/5/2024 AK E-Line Perf
BRU 242-04 50283201640000 212041 3/20/2024 AK E-Line JB/PProf
NCIU A-17 50883201880000 223031 3/27/2024 AK E-Line GPT/Perf
PBU 05-02A 50029201440100 201241 4/6/2024 Halliburton PPROF
PBU 09-35A 50029213140100 193031 4/9/2024 Halliburton RBT
PBU 13-24A 50029207390100 204243 4/5/2024 Halliburton RBT
PBU B-14A 50029203490100 209059 4/2/2024 Halliburton RBT
PBU D-31B 50029226720200 212168 4/7/2024 Halliburton PERF
SRU 222-33 50133207150000 223100 3/27/2024 AK E-Line CIBP/Perf
SRU 224-10 50133101380100 222124 3/29/2024 AK E-Line CIBP/Perf
SRU 241-33B 50133206960000 221053 4/2/2024 AK E-Line CIBP
Please include current contact information if different from above
T38718
T38719
T38720
T38721
T38722
T38723
T38724
T38725
T38726
T38727
T38728
BRU 241-23 50283201910000 223061 4/5/2024 AK E-Line Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.19 14:54:13 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/4/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240404
Well API #PTD #Log Date Log Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF
BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf
HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT
KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF
KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF
KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF
END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF
MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey
MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter
MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL
NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf
NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf
PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT
PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF
PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF
PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF
PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF
SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF
SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf
Please include current contact information if different from above
T38683
T38684
T38685
T38686
T38689
T38687
T38690
T38691
T38691T38692
T38963
T38963
T38694
T38694
T38694
T38695
T38696
T38697
T38698
BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.09 13:48:29 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 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):
7,515' N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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
jake.flora@hilcorp.com
907-777-8442
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:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
Tubing Grade: 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
ADL0021128
223-061
50-283-20191-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
2,849'
8,430psi
2,799'
Size
120'
3,949'
MD
See Attached Schematic
2,980psi
6,890psi
120'120'
3,049'
March 25, 2024
Tieback
7,513'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 241-23CO 802
Same
7,159'4-1/2"
~1486psi
4,672'
N/A
Length
LTP; N/A 2,846' MD/ 2,533' TVD; N/A, N/A
7,161' 7,429' 7,075'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
6
t
t
c
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.03.11 13:49:31 -
08'00'
Noel Nocas
(4361)
By Grace Christianson at 3:30 pm, Mar 11, 2024
DSR-3/11/24
Dump bail 25' of cement on top of CIBP at 5000' MD before adding additional perfs.
A.Dewhurst 20MAR24
10-404
BJM 3/19/24JLC 3/20/2024
Hilcorh Alapka, L.IA.
Date: 12/07/2023
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
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99S01
DATA TRANSMITTAL
BRU 241-23
- PTD 223-061
- API 50-283-20191-00-00
Washed and Dried Well Samples (09/16/2023)
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 241-23
BOX 1 OF 3
2970' - 4620' MD
BRU 241-23
BOX 2 OF 3
4620' - 6210' MD
BRU 241-23
BOX 3 OF 3
6210' - 7515' MD
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received N Date:
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: 78.1' 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" X-56 120'
7-5/8" L-80 2,799'
4-1/2" L-80 7,159'
4-1/2" L-80 2,624'
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:
00963 0
12/2/2023 24
Flow Tubing
0
2992
N/A29920
N/A
N/A
N/A
7,515' MD / 7,161' TVD
7,429' MD / 7,075' TVD
819' FNL, 546' FEL, Sec 23, T13N, R10W, SM, AK
371' FNL, 757' FEL, Sec 23, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
2,849'
2,617'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
10/7/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
322808
322605
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.
BRU 241-23September 15, 20232162' FNL, 60' FWL, Sec 24, T13N, R10W, SM, AK
96.6'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2634820
SETTING DEPTH TVD
2635271
TOP HOLE SIZE
CBL 9-27-23, Mudlogs, LWD (AGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs
Sterling - Beluga Gas Pool
ADL 21128
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
323392 2633474
50-283-20191-00-00September 6, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
10/1/2023 223-061 / 323-526
N/A
PACKER SET (MD/TVD)
Conductor
9-7/8"
Driven
Surface L - 427 sx / T - 173 sx
12.6#
Surface
Surface
3,049'
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,841' 7,513'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy. Tieback
TUBING RECORD
L - 347 sx / T - 99 sx6-3/4"
N/A
SIZE DEPTH SET (MD)
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 3:31 pm, Dec 12, 2023
Completed
10/1/2023
JSB
RBDMS JSB 122823
G
BRU 241-23
223-061 / 323-526
DSR-1/29/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Beluga E6 4,603' 4,291'
3770' 3469'
4140' 3832'
4342' 4031'
4693' 4378'
5132' 4811'
5451' 5125'
6157' 5821'
6710' 6365'
7381' 7026'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
INSTRUCTIONS
Beluag J6
Beluga H
Beluga I
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Beluga F
Sterling B1
Beluga G
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.
Beluga J
Beluga D
TPI (Top of Producing Interval).
Authorized Name and
Beluga E
Formation Name at TD:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
12/12/23
Monty M
Myers
Updated by CJD 12-12-23
Schematic
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
RKB to GL = 18.5’
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD Date Status
E6 4,603’ 4,609’ 4,291’ 4,297’ 11/25/23 Open
E6 4,616’ 4,620’ 4,304’ 4,308’ 11/25/23 Open
E6 4,685’ 4,690’ 4,371’ 4,376’ 10/22/23 Open
F7 5,024' 5,052' 4,706' 4,734' 10/12/23 Isolated
F10 5,076' 5,081' 4,758' 4,763' 10/12/23 Isolated
F10 5,105' 5,109' 4,786' 4,790' 10/12/23 Isolated
F10 5,116' 5,119' 4,797' 4,800' 10/12/23 Isolated
F10 5,124' 5,129' 4,805' 4,810' 10/12/23 Isolated
G1 5,153' 5,161' 4,834' 4,842' 10/11/23 Isolated
G2 5,197' 5,200' 4,877' 4,880' 10/11/23 Isolated
G2 5,214' 5,219' 4,894' 4,899' 10/11/23 Isolated
G5 5,286' 5,292' 4,965' 4,971' 10/10/23 Isolated
G9 5,405' 5,407' 5,082' 5,084' 10/10/23 Isolated
H 5,467' 5,469' 5,143' 5,145' 10/10/23 Isolated
H 5,481' 5,483' 5,157' 5,159' 10/10/23 Isolated
H 5,489' 5,495' 5,165' 5,171' 10/6/2023 Isolated
H2 5,534' 5,537' 5,209' 5,212' 10/6/2023 Isolated
H2 5,541' 5,547' 5,216' 5,222' 10/6/2023 Isolated
H3 5,569' 5,573' 5,244' 5,247' 10/6/2023 Isolated
H3 5,582' 5,585' 5,256' 5,259' 10/6/2023 Isolated
H5 5,666' 5,670' 5,339' 5,343' 10/6/2023 Isolated
H5 5,673' 5,676' 5,346' 5,349' 10/6/2023 Isolated
H8 5,766' 5,768' 5,437' 5,439' 10/6/2023 Isolated
H8 5,770' 5,775' 5,441' 5,446' 10/6/2023 Isolated
H8 5,781' 5,789' 5,452' 5,460' 10/6/2023 Isolated
H15 6,091' 6,111' 5,758' 5,777' 10/5/2023 Isolated
I 6,174' 6,180' 5,839' 5,845' 10/5/2023 Isolated
I1 6,219' 6,231' 5,884' 5,896' 10/3/2023 Isolated
I2 6,254' 6,268’ 5,919' 5,933' 10/3/2023 Isolated
I2 6,300' 6,304' 5,964' 5,968' 10/3/2023 Isolated
I3 6,318' 6,324' 5,982' 5,988' 10/3/2023 Isolated
I6 6,418' 6,438' 6,080' 6,100' 10/3/2023 Isolated
I11 6,620' 6,626' 6,279' 6,285' 10/1/2023 Isolated
J2 6,881' 6,905' 6,535' 6,559' 10/1/2023 Isolated
J5 7,174' 7,185' 6,824' 6,835' 10/1/2023 Isolated
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,841’ 7,513’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,849’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,506’ 3.958” 4.780” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 5,000’ - 4.500” CIBP (3.71” OD) Set 10-21-23
4 6,070’ - 4.500” CIBP (3.71” OD) Set 10-05-23
5 6,204’ - 4.500” CIBP (3.71” OD) Set 10-05-23
6 6,595’ - 4.500” CIBP (3.71” OD) Set 10-02-23
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) 12.0 ppg lead, 173 sx (33 bbls) 15.8 ppg tail, returned all spacer and
87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) 12 ppg lead, 99sks (22 bbls) 15.3 ppg tail cement. Bumped plug
and circulated 50 bbls of cement off liner top. TOC @ 2850’ (9-27-23 CBL)
6-3/4”
hole
2
1
3
4
5
6
Activity Date Ops Summary
9/2/2023 Opened ram doors, cleaned and inspected ram cavities, buttoned up doors. tore out cuttings box and removed centrifuge, RD poorboy degasser in prep to lay
over, undressed rig floor, L/D mousehole, removed kelly hose and service loop from topdrive, removed flow line,;removed pump skid interconnects, removed
and C/O valves and seats, un-pinned torque bushing from topdrive and L/D same, emptied all dumpsters at dump, PU and transferred topdrive to cradle, un-
pinned and layed down poorboy degasser skid, load available rig mats;mud lab and degasser skid and transport to K pad, removed topdrive from floor, pulled
flow riser, fold back beaver slide, spot crane, transferred BOP stack to cradle and staged master valve in cellar, tore out aux fuel tank, transported fuel tank and
topdrive to K pad.;Tore out boiler skid, transported boiler skid to K pad, staged HandyBerm conex on pad, installed master valve on wellhead, WHR tested seals
at 5K for 10 min, good test, topped off master and tested at 3500 psi, good test. Scoped derrick to half mast, Removed;lower section of TQ tube and L/D on
catwalk. Finished R/D pits modules 1-3, and MP's 1&2, lowered roofs on a 3 pit modules. R/D TD HPU and air/water lines throughout the rig, blew down same.
Unplugged 80% of all electrical. Dressed down mast to be lowered.;Crew change, held PTSM. Cont. R/D, prepping rig to move, and hauling misc. loads to K-pad
or the staging pad. R/D grasshoppers and Pason cables. Unspooled drilling line from drum, cut 25 wraps of drilling line. Hung Kelley hose, service loop, and
drilling line in mast.;Performed derrick inspection. Prepped derrick to be laid over. R/D derrick board. Tore out HandyBerm around rig foot print, loaded in to
conex, and hauled conex to staging area. Loaded out CCI's conex. P/U & loaded out 6 rig mats form back yard area,;hauled to K-pad and set to complete
matting board layout. Currently laying down the mast.
9/3/2023 Held PJSM, Lay over mast. CCI trucks on location at 06:30. Un-pinned hoist rams from derrick, dis-connected hyd hoses and electric cords from derrick.
Removed lights, camera and gas alarms from doghouse roof;CCI tore out clam shell and pump skids, jig, pit 3 and 2. Loaded these itmes and transported to K
pad in Beluga. Stacked exposed rig mats, lowered doghouse, cleaned up exposed liner and felt. Tore out pit 1, catwalk, gen skid, HPU skid and
doghouse.;Loaded and transported to K pad, stacked exposed mats, cleaned up exposed liner and felt. Staged cranes, picked iron roughneck off rig floor.;RU on
derrick, picked derrick off carrier, picked carrier off sub, picked sub off pony walls. Transported these along with cranes to K pad. Loaded rig mats and pony walls
and transported same. Stacked remaining mats on C pad, cleaned up liner and felt.;Set pony walls on K pad, set sub on pony walls and centered over well, set
carrier on sub, set derrick on carrier. Set doghouse skid.;Set all three pit mods, jig and pump skids. Set gen skid and fired gen, M/U HYD lines to rig floor, stood
mast, raised doghouse. Set TD HPU, parts C-can. Raised pit roofs, Worked on running cables and plugging in electrical between modules, and R/U pumps and
pit system.;Crew change. Cont. w/ R/U. Hauled water from E-pad and filled rig water tank. Cleaned out area on the northeast corner of K-pad, laid mats to spot &
set office, sleeper, and meeting trailers in the morning. R/U derrick board, tied up derrick fingers, removed Kelley;hoes, and drill line from tuggers hanging in the
derrick. R/U rig HPU, prepped DWKS for spooling up drill line. R/U drillers control/ stucchi fittings under doghouse. Held PJSM on spool up, spooled up drill line
to drum. Unhung blocks, untied derrick assist. Laid felt & liner;for catwalk, R/U TD HYD lines on rig floor. R/U water & air lines through out rig. Cont. working on
run electrical lines. Started R/U Pelco rig cameras and Pason cords. R/U weight indicator and prepped derrick to scope. Cont. w/ R/U.
9/4/2023 Sent State 48 hr notice for diverter function test, set catwalk, set centrifuge and cuttings box, RD comms on C pad, RD 4 trailers and change shack on C pad,
transported trailers and various equipment to K pad, set both boiler skids, 40' connex, set upright water tank, PU and pinned lower torque;tube to upper section,
scoped up derrick, set sleeper, push shack and change shacks.;Installed "T" bar on torque tube, installed torque bushing on torque tube, RU and staged topdrive
on rig floor, cont to set safety shack and Co Rep trailer, strung cords and powered up trailers, RU comm's in trailers and to service shacks, installed omni wrap
on kelly hose.;raised vac degasser and plumbed in, MU service loop on topdrive, cont stringing cords and jumpers in pits.;Installed Kelly hose on topdrive and
ran through derrick to check position, cont. working on rig acceptance checklist, Changed out valve on pulsation dampener and refilled. Checked bottle back
pressures on koomey. Removed shipping beams in sub base. Filled pits w/;water and hydro tested. Function tested centrifugal pumps, shakers, agitators, and
butterfly valves. Function test TD robotics. Built 90 bbl batch of spud mud. Turned diverter T to correct position out of sub base. N/U knife valve to T, and started
on N/U of vent line.;Crew change, held PTSM. Cont. to N/U diverter system. M/U remaining vent lines and anchors. N/U flow riser, chained of stack in sub. N/U
flow line from riser to possum belly. M/U koomey lines to annular. Energized koomey.;Finished 2nd batch of spud mud, started on third batch. Cont. hauling off
equip./misc. items from Lewis River C-pad. Cont. R/U, building mud, and working through rig acceptance check list.
9/5/2023 Function test Diverter, Adjust vent line and function again. Function centrifuge, Continue working Rig Acceptance Checklist, Berm in Rig Footprint, Test run mud
pumps, Test mud line T/ 2500 psi. Good. Confirmed Engine ESD's working properly. Install;Mousehole in the rotary, P/U & M/U stands of 4-1/2" Drill Pipe and
HWDP for surface hole. Accepted rig @ 12:00 hrs.;Crew change, held PTSM. Finished building 40 stds of 4.5" DP and 8 stds of HWDP. Finished building spud
mud (415 bbls total). Brought out MWD tools, racked & tested tools (ok).;Disassembled IR rollers, replaced bearing & bolts. Brought out CCI welder, started
working through misc. welding projects. Built 5 stds of 4.5" DP and racked back. P/U & M/U 6-3/4" flex collar std. M/U jar std. Racked and tallied additional 45 jts
of 4.5" DP. Cont. building;stds. and prepping welding projects for welder in the morning.;Crew change, held PTSM. Cont. building 4.5" DP std. Racking back a
total of 72 stds. Strapped E-Kelley = 30.97'.;P/U E-Kelley, retested for confirmation for closer of annular and opening of knife valve = 27 sec. Strapped & tallied 9-
7/8" surface casing on H-pad. L/D rotary table mouse hole.;Rig service- Greased & inspected, crown, TD, IR, DWKS, brake linkage, drive line, wash pipe, and
inspected threads on saver sub. Checked pressures on MP pulsations dampeners.;Cont. building first batch of production interval mud. Worked on
housekeeping, pressure washing, and organizing of rig modules.
9/6/2023 Continue working through welding list, Test gas alarms Visual & Audible with Quadco (Good). Post rig location sign. Function Test Diverter stack to keep the gas
system test & function test on same date. 29 seconds for 21-1/4" Diverter to close & 27 seconds for knife valve to open.;M/U BHA #1 6-3/4" Motor & 9-7/8"
Kymera Bit. RIH with HWDP & tag fill @ 135'. POOH Standing back HWDP T/ mud motor & M/U DM Collar & EWR-M5 Collar. Oreint MWD w/ motor at
RFO=78.52. M/U TM HOC & upload MWD.;RIH with BHA #1 F/ 77' T/ 130'. Swap well over to 8.8ppg Spud Mud, Observe & repair leak on flange between Tee &
Knife valve. Wash down T/ 139'. POOH, Stand Back HWDP RIH with Flex Collar stand & M/U first HWDP stand.;Drill 9-7/8" Surface section F/ 139' T/ 375' P/U-
30K S/O-22K ROT-30K GPM-400 SPP 870 psi. TQ 1-4K RPM 40 ECD 9.6 ppg MW in 8.95ppg Vis 205 MW out 9.0ppg Vis 206.;Cont. directional drilling 9-7/8"
surface hole at 3 degrees per/100' build section F/375'-T/803'. P/U-40K S/O-37K ROT-38K GPM-450 SPP-1100 psi. Diff-50 psi WOB-2K TQ-2.9K RPM 60
ECD 9.7 ppg MW-9.0 ppg Gas- 0 units.;Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole, sliding at 3 degrees per/100' in build section
F/803' to current depth of 1286'. P/U-42K S/O-38K ROT-40K GPM-450 SPP-1158 psi. Diff-45 psi WOB-2K TQ-3.3K RPM 60 ECD 9.9 ppg.;MW-9.0 ppg Gas- 0
units Total Krevs-334.6. Distance to well plan: 7.76' 7.59' High 1.63' Right.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 241-23
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00092 BRU 241-23 Drilling
Spud Date:
9/7/2023 Continue directional drilling 9-7/8" Surface section F/ 1286' T/ 1382' P/U 42K S/O 38K ROT 40K GPM 450 SPP 1130 psi. Diff 60 psi. WOB-1K TQ-3.2K RPM 60
ECD 9.6 ppg. Holding tangent at +/- 28 Inclination F/ 1303' MD. CBU.;Monitor Well, Static. POOH on elevators F/ 1382' T/ 375' & Slack Off T/ 394' P/U 49K S/O
43K with no issues, Two tight spots wiped clean (1040' 10K overpull & 488' 20K overpull) Calculated hole fill: 8.12 BBLs Actual hole fill: 10.25 BBLs.;Service &
Inspect Crown, Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor Motor, Draworks, Crown-O-Matic, Gear Box, Drive Line & Brake Linkage. Change out
Swab, Liner, Valve & Seat on MP#1 Pod#3. Clean both MP suction screens. Static Loss Rate= .75 BPH.;RIH on elevators F/ 394' T/ 1382' with no issues. P/U
45K S/O 35K. Calculated displacement: 15.8 BBLs Actual displacement: 16.84 BBLs.;Fill pipe & wash last stand down (No Fill) Pump 20 BBLs Hi-Vis sweep STS
@ GPM 490 SPP 1350psi. While reciprocating & rotating. Sweep came back 3.8 BBLs late with no increase in cuttings.;Drill 9-7/8" Surface section F/ 1382' T/
1539' P/U 47K S/O 42K ROT 43K TQ 4.1K RPM 60 GPM 450 SPP 1200psi Diff 30psi WOB 1K Max Gas 0 units MW in 8.95ppg MW out 8.95ppg ECD
9.67ppg.;Cont. Drilling Surface section F/1539'-T/2064'. Pulled early wiper trip due to losing swab & liner in MP #2 pod #2 and swab in MP#1 pod #2. CBU, shot
on bottom survey, and flow checked well- static.;P/U 59K S/O 45K ROT 50K TQ 5.3K RPM 60 GPM 450 SPP 1200 psi Diff 15 psi WOB 2K Max Gas 4 units MW
9.0 ppg ECD 9.68 ppg.;POOH on elevators F/2064'-T/1382' w/ no issues. P/U-62K S/O-42K Hole fill Calculated- 5.63 bbls Act-xxx bbls Diff- xxbbls. Changed out
liner and swabs during the trip.;Serviced rig while monitoring hole on TT. Greased & inspected crown, TD, blocks, IR, wash pipe, brake linkage, and drive shaft.
Cleaned out both MP bear traps. Static loss rate = 1.12 bph.;RIH on elevators F/1382'-T/2002' w/ no issues. Washed last std. to bottom w/ no fill. Shut down MP
#2 to retighten liner. P/U-46K S/O-39K Calculated pipe Disp-12.2 bbls Act-11.18 bbls Diff-1.02 bbls.;Pumped 20 bbl Hi-Vis sweep w/ walnut/condet w/ MP #1
while fixing MP #2. Sweep came back on time w/ a 30% increase in cuttings. GPM-335 SPP-784 RPM-60 TQ-4.7K ECD-9.5 ppg Max gas-2 units.;Resumed
directional drilling 9-7/8" surface hole w/ both MP's F/2064'-T/2186'.P/U-64K S/O-44K ROT-50K GPM-450 SPP-1280 psi. Diff-15 psi WOB-1K TQ-5.3K RPM 60
ECD 9.87 ppg MW-8.95 ppg Gas- 2 units.;Crew change, held PTSM. Cont. directional drilling 9-7/8" surface hole F/2186' to current depth of 2705'. P/U-60K S/O-
42K ROT-50K GPM-450 SPP-1444 psi. Diff-15 psi WOB-2K TQ-6.3K RPM 60 ECD 9.7 ppg MW-8.95 ppg Gas- 25 units Krevs- 446.;Distance to well plan: 2.82'
1.21' Low 2.54' Left.
9/8/2023 Continue directional drilling 9-7/8" Surface section F/ 2705' T/ 3059'MD 2808'TVD P/U 64K S/O 43K ROT 54K GPM 450-500 SPP 1600-1850psi. Diff 120-
155psi. WOB18-30K TQ 8.5K ft/lbs. RPM 60-80 ECD 9.6 ppg.;Observed transition into Loose Sand/ Clay formation @ 2958'. Circulate Bottoms Up & obtain
bottom survey. Extrapolated to surface TD: 6.07' from wp07 5.97' high 1.08' right. Submit 48-hour notice to AOGCC for BOPE Test.;Monitor Well with slight
seepage. POOH F/3059' T/ 360' (Jars) & Lower back T/ 422'. P/U 70K S/O 44K. Calculated Hole Fill 19.8 BBLs Actual Hole Fill 25.37 BBLs.;Service & Inspect
Crown, Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor Motor, Draworks, Drive Line, Brake Linkage, Checked Reiner Motor Bolts & Tie Wired Bolts. Clean
out suction screens for Mud Pumps. Static Loss Rate 1.78 BBL Per Hour.;RIH on elevators F/422'-T/3059', washing last std. to bottom w/ no issues or fill on
bottom. P/U-60K S/O-44K Pipe displacement Cal=51.24 bbls Act=45.58 bbls Diff=5.66 bbls.;Pumped 23 bbls Hi-Vis sweep w. walnut/condet, sweep came
back 7.3 bbls late w/ a 30% increase in cuttings. Circ. till shakers cleaned up. Flow checked well- static. P/U-60K S/O-44K ROT-52K GPM-454 SPP-1350 psi
RPM-80 TQ-6.5K MW-9.0 ppg ECD-9.6 ppg.;POOH on elevators F/3059'-T/703' w/ no issues. Racked back HWDP, L/D jar std. & flex collars. Plugged in and
down loaded MWD data. Hole fill Cal=22.26 bbls Act=32.25 bbls Diff=9.99 bbls.;Crew change, held PTSM. L/D remainder of BHA #1. Bit graded PDC- 1-1CT-A-
X-1-NO-TD Cones- 1-1-WT-A-E-1-NO-TD 1/16" under gage. Cleaned & cleared rig floor. Drained stack. Test run hanger and made mark on LJ.;R/U TRS
casing handling equip. Cleaned casing threads on shoe track. Held PJSM on running 7-5/8" casing.;M/U shoe track and BakerLok connections. Tested floats
(ok). Cont. running 7-5/8" TXP 29.7# L-80 surface casing as per run tally. Distance to well plan: 4.62' 4.49' High 1.11' Right.
9/9/2023 Continue running 7-5/8" 29.7# L-80 TXP Casing F/ 1205' T/ 3021' as per running tally Torqueing connections T/ 17,740 ft/ lbs. Installing cementralizers every
other jt. until 300' F/ Surface. P/U and M/U 7-5/8" Hanger with landing jt. & RIH T/ 3049' & land on;landing ring. P/U 90K S/O 42K Calculated displacement 27.5
BBLs Actual displacement 23.3 BBLs.;M/U casing swedge & circulate up to 5 BPM W/ 75 psi. Install Bale extensions & remove casing swedge. Load plugs in
cement head with DSM witness & install quick latch head on landing jt. R/D TRS services & R/U Halliburton cementers.;PJSM with all parties for surface cement
job. Line up & pump 5 BBLs ahead at 2 BPM 112psi. Close cement head valve PT low T/ 460psi. PT High T/ 3300psi. Good Test. Pump 60 BBLs 10.5ppg
Tuned Prime Spacer 4 BPM 195psi. DSM witness drop bottom;plug. Pump 427 sacks of lead cement at 12.00ppg 2.44 3ft/sk 14.399 gal/ sack Pump a total of
190 BBLs 4 BPM 158psi. Pump 173 sacks of tail cement 15.80ppg 1.16 3ft/sk 5.028 gal/ sack Pump a total of 33 BBLs 4 BPM 225psi. DSM witness drop top
plug.;Pump 136 BBLs of 9.4 ppg mud 4 BPM 166psi with cement truck. Slow rate for last 10 BBLs 2 BPM 630psi. Bumped plug at 132 BBLs at 690psi pressure
up to 1300psi. CIP @ 14:35. Check floats & bled back 1 BBL. 60 BBLs of Spacer & 87 BBLs cement returned to surface with no losses.;B/D & R/D cementers,
Remove cement head and flush. Back out landing joint, wash down & L/D. M/U stack washer & wash 21-1/4" Diverter stack & flow line with black water. Tear out
vent line, Knife valve, flowline, fill line, riser & flowbox. N/D 21-1/4" Annular.;Changed oil & filters on office generator. Hauled off mud from pits 1-6 and cleaned
out tanks bottoms. Removed pre charge pump in hopper house #1 and replaced w/ same.;N/U well head as per WHR, tested tubing seals T/5K of 10 min (ok).
Worked on weighting up 1st batch on new 6% KCL PHPA mud.;Hung flow box, N/U 2' spacer to well head. Picked BOP's from cradle and transferred to bridge
cranes in sub base. Set BOP stack on spacer spool and N/U. Bolted up Kill/choke lines to stack. Chained off stack.;Attempted to remove broken Rineer
mounting bolt from gear box w/ left handed drill bit (no luck). Unbolted Rineer motor from TD. Worked on changing out pre charge pump in hopper house
#1.;Crew change, held PTSM. Finished torqueing bolts on TD. M/U HYD koomey lines to stack. Finished installing premix pump and tested (ok). M/U bell nipple,
riser, and flow line to stack. Attempted to remove broken bolts w/ easy out (no luck). Removed centrifugal;pump in hopper house #2 due to mechanical seal
leaking. Installed test plug/test jt. Greased choke manifold, mezz valves, and inside/HCR choke & kill. Energized koomey. Function tested BOP's components.
Pulled test jt./plug. Attempted to close blinds at panel;( no luck). Working through electrical BOP control panel issue. Reinstalled test jt. flooded stack, lines, and
choke manifold w/ water. Currently hammering up leaks on stack. BOP test witness waived by Jim Regg.
9/10/2023 Attempt shell test with leak observed on ODS Blind Ram shaft seal weep hole. Evacuate water & pull test joint, Re-Install centrifugal in hopper 2 & test
good.;Open ODS Blind Ram door. Replace seals for ODS Blind Ram Shaft seal. Continue working on getting sheared bolts out of top drive where Rineer motor
bolts up.;R/U & fill BOPE stack, Purge choke manifold, Kill line & Test joint. Observed ODS blind ram door seal leaking. Evacuate stack & open ram door,
replace seal & close ram door. Purge equipment and obtain successful shell test.;Test BOPE with 4-1/2" Test joint. Tested annular T/ 250/ 2500psi. Tested BOP
components T/ 250/3500psi for 5/5.Had F/P on 4 tests. Test # 2- had leak on spacer spool, hammered up spacer spool, retested-Passed. Test #3- HCR kill,
serviced & functioned,;retested-Passed. Test #6- Choke HCR, serviced & functioned, retested-Passed. Test #7. Wouldn't hold pressure on the low test,
Changed LPR to 4.5" fixed bodies, Failed. discovered leak on FOSV, replaced TIW, retested-Passed. Total testing time 12 hrs. Quadco Rep;tested audio/visual
on gas alarm system.;Pulled test jt./test plug. Set 9" wear ring. R/U and tested 7-5/8" surface casing T/3500 psi on a chart for 30 min (good test). Pumped in
1.73 bbls Bled back 1.72 bbls. R/D testing equip. Flushed water through lines and blew down same. Re-greased choke manifold.;Cleaned & cleared rig floor,
Installed short mouse hole. M/U mule to single jt. of 4.5" DP. P/U and singling in the hole w/ 26 jts. of 4.5" DP. POOH and racked back 13 stds. in the
derrick.;Currently staging 6-3/4" BHA #2 on the catwalk.
9/11/2023 PJSM for P/U HES triple combo BHA #2. P/U all crossovers & 6-3/4" PDC bit. P/U 4-3/4" Mud Motor & M/U 6-3/4" HBDS PDC Bit. P/U & M/U DM, PCG, ADR,
ALD, CTN, PWD & TM Collars. RFO= 248.2 Upload data & Shallow pulse test. PJSM & load sources. P/U & M/U Flex collars, Jars & HW DP T/ 740'.;RIH with
BHA #2 Picking up drill pipe needed to TD well F/ 740' T/ 2321' RIH F/ Derrick F/ 2321' T/ 2905' P/U 60K S/O 43K.;M/U TD & wash/ ream down. locate plugs at
2958' Drill through plugs & Float Collar, Drill through cement and Float Shoe at 3049' drill through cement and 20' of new formation T/ 3079' GPM 196
SPP1010psi. TQ 6K RPM 30 P/U 62K S/O 42K ROT 50K.;Displace well F/ Spud Mud T/ 6% KCL PHPA mud while reciprocating. GPM 196 SPP 1040psi.
Confirm good 9.0ppg in & 9.0ppg out.;R/U & purge all lines for FIT @ 3049' MD 2799' TVD with 9.0ppg mud. Pressure up to 675psi with 14.7 gallons when
formation broke away. in 15 minutes, pressure bled from 675psi. T/ 80psi. Bled off 3 Gallons. LOT result 13.64ppg EMW.;Slip & cut 6 wraps of drill line (28').
Obtained new SPR's.;Drilled ahead F/3079'-T/3124'. Lost communications w/ MWD tools. Attempted to cycle pump w/ mode swap, did hard reset. (no luck).
Decision was made to POOH and re-download data to MWD tools. Flow checked well. P/U-64K S/O-46K ROT-54K GPM-215.;SPP-1193 psi Diff-216 psi TQ-
4.6K RPM-60 WOB-05K MW-9.0 ECD-9.6 ppg Max gas 7 units.;POOH F/3124'-T/BHA #2, racked back HWDP and jar std. Hole fill- Cal=19.44 bbls Act=20.64
bbls Diff=1.2 bbls.;Crew change, held PTSM. Cont. POOH, racked back flex collars. removed sources. Plugged in at TM collar. Downloaded and read data,
discovered resistivity sampling tool had turned on during initial shallow pulse test and then shut off at some point. Re-downloaded;data to MWD tools. Performed
11 min shallow pulse test confirming tool was functioning properly (ok).;RIH F/121'-T/3124', washing last std. to bottom. P/U-68K S/O-50K Pipe Disp.- Cal=50.45
bbls Act=46.44bbls Diff=4.01 bbls.;Resumed directional drilling ahead F/3124' to current depth of 3174'. P/U-68K S/O-50K ROT-60K GPM-220 SPP-1301 psi
Diff-125 psi TQ-4.8 RPM-60 WOB-2/5K MW-9.0 ECD-9.6 ppg Max gas 9 units. Distance to well plan: 6.31' 6.21' High 1.14' Right.
9/12/2023 Continue Drilling 6-3/4" F/3174' T/ 3618'. P/U 71K S/O 55K ROT 62K GPM 220 SPP 1288psi Diff 53psi TQ 5.2K RPM 45 WOB 2/5K MW 9.0 ECD 9.8ppg Max
gas 16 units.;Drill 6-3/4" F/ 3618' T/ 4205' P/U 77K S/O 56K ROT 64K GPM 220 SPP 1250psi Diff 53psi TQ 56.4K RPM 60 WOB 2/5K MW 9.0 ECD 9.8ppg Max
gas 610 units.;CBU, Obtain survey and SPRs, Flow check well Static slight loss.;Make wiper trip f/ 4205' t/ 3032' on elevators no hole issues.;Service rig and top
drive, grease crown, inspect brakes and drive shaft.;RIH f/ 3032' t/ 4205' with no issues wash last stand to bottom, pump Hi Vis Sweep.;Drill 6-3/4" F/ 4205' T/
4701' P/U 81K S/O 60K ROT 72K GPM 220 SPP 1480psi Diff 200psi TQ 7.5K RPM 70 WOB 2/5K MW 9.0 ECD 10.1ppg Max gas 426 units. Distance to Plan
5.59' 467' High 2.56' Left.
9/13/2023 Drill 6-3/4" F/ 4701' T/ 5067' P/U 95K S/O 67K ROT 78K GPM 205 SPP 1630psi Diff 180psi TQ 7.9K RPM 65 WOB 5K ECD 10.28ppg MW in/out 9.05ppg Max
gas 206 units. SPRs @ 4750'md 4447'tvd MP #1 SPM 20 PSI 271 MP #2 SPM 22 PSI 275.;Drill 6-3/4" F/ 5067' T/ 5315' P/U 96K S/O 65K ROT 78K GPM 205
SPP 1484psi Diff 180psi TQ 8.7K RPM 65 WOB 5K ECD 10.39ppg MW in/out 9.1ppg Max gas 772 units. SPRs @ 5315'md 4992'tvd MP #1 SPM 20 PSI 252
MP #2 SPM 20 PSI 243.;CBU GPM 205 SPP 1357 RPM 65 TQ 8K P/U 96K S/O 65K ROT 76K. Shoot survey on bottom.;Monitor Well, Slight Seepage. POOH
F/ 5313' T/ 4205' with no issues. Calculated Hole Fill 7.1 BBLs Actual Hole Fill 4.8 BBLs.;Monitor Well on Trip Tank while performing rig service. Grease &
Inspect Crown, Blocks, Top Drive, Iron Roughneck, Draworks & check all fluids in motors.;RIH F/ 4205' T/ 5250' Calculated Displacement 18.3 BBLs Actual
Displacement 17.7 BBLs M/U Top Drive & fill pipe wash last stand down @ GPM 70 SPP 340psi.;Drill 6-3/4" F/ 5315' T/ 5563' P/U 100K S/O 60K ROT 78K GPM
205 SPP 1687psi Diff 405psi TQ 8.9K RPM 65 WOB 5K ECD 10.22ppg MW in/out 9.1ppg Max gas 3050 units.;Drill 6-3/4" F/ 5563' T/ 5810' P/U 102K S/O 65K
ROT 79K GPM 205 SPP 1620psi Diff 300psi TQ 8.3K RPM 65 WOB 10K ECD 10.3ppg MW in/out 9.1ppg Max gas 202 units. Distance f/ plan 3.30' 1.13' Low
3.09' Left.
9/14/2023 Drill 6-3/4" F/ 5810' T/ 6090' P/U 105K S/O 68K ROT 80K GPM 220 SPP 1970psi Diff 380psi TQ 9.5K RPM 65 WOB 5/10K ECD 10.49ppg MW in/out 9.15ppg
Max gas 224 units. SPRs @ 5870' MD 5540' TVD MP #1 SPM 20 PSI 314 MP #2 SPM 21 PSI 311.;Drill 6-3/4" F/ 6090' T/ 6432' P/U 114K S/O 66K ROT 84K
GPM 220 SPP 1900psi Diff 325psi TQ 10.8K RPM 65 WOB 5/10K ECD 10.7ppg MW in/out 9.2ppg Max gas 147 units. SPRs @ 6432' MD 6094' TVD MP #1
SPM 20 PSI 272 MP #2 SPM 21 PSI 289.;CBU @ 6432' GPM 210 SPP 1432 RPM 66 TQ 10K P/U 116K S/O 66K ROT 86K ECD 10.34ppg.;Make wiper trip f/
6432' t/ 3031' with no issues, 21.8 bbls calc 24.1 bbls act.;Service rig and top drive, grease crown and service draw works.;RIH f/ 3031' t/ 6432' with no issues
wash last stand to bottom.;Drill 6-3/4" F/ 6432' T/ 6679' P/U 117K S/O 73K ROT 89K GPM 220 SPP 1925psi Diff 400psi TQ 10K RPM 70 WOB 5/10K ECD
10.5ppg MW in/out 9.3ppg Max gas 83 units Distance from Plan 7.58' 6.42' Low 4.02' Right.
9/15/2023 Drill 6-3/4" F/ 6679' T/ 6926' P/U 122K S/O 73K ROT 91K GPM 220 SPP 1900psi Diff 300psi TQ 11.3K RPM 70 WOB 5K ECD 10.78ppg MW in/out 9.35ppg
Max gas 168 units.;Drill 6-3/4" F/ 6926' T/ 7225' P/U 130K S/O 76K ROT 96K GPM 220 SPP 1970psi Diff 340psi TQ 11.1K RPM 70 WOB 5K ECD 10.75ppg
MW in/out 9.35ppg Max gas 150 units.;Drill 6-3/4" F/ 7225' T/ 7515' P/U 130K S/O 76K ROT 96K GPM 220 SPP 2065psi Diff 340psi TQ 12.1K RPM 70 WOB 5K
ECD 10.93ppg MW in/out 9.35ppg Max gas 179 units. Pump Hi Vis sweep around.;Pump 20 bbl hi vis sweep, sweep back 18 bbls early, 40 % increase in
cuttings, get survey and SPR's, Flow check well static.;POOH f/ 7515' t/ 5925' over pulling 15k-25k slight swabbing.;Circulate bottoms up 205 gpm 1400 psi, no
increase in cuttings or gas on bottoms up.;Continue POOH f/ 5925' t/ 4512' No more hole issues hole taking correct fill.
9/16/2023 POOH with BHA #2 6-3/4" Triple Combo F/ 4512' T/ 742' with no issues P/U 92K S/O 67K.;Flow check well for 10 minutes, Static. POOH & stand back 5 stands
HWDP, Jar stand, 3 stands HWDP & Flex collars. PJSM, Remove sources & Download MWD. L/D remaining BHA. Bit graded 1-1. Calculated Fill for entire trip
52 BBLs Actual Fill 57.17 BBLs.;Clear & Clean rig floor.;Grease & Inspect Blocks, Top Drive, Crown, Draworks, Iron Roughneck, Swivel, Gear Box, Driveline &
Brake Linkage. Inspect Brake Bands on draworks & adjust kick rollers. Change out stem & seat on electric choke. Change low torque valve on stand pipe.
Monitor well on trip tank loss rate: 0.6 BPH.;P/U & M/U 6-3/4" dumb iron with Tri-Cone Bit RIH with flex collars & HWDP T/ 661' P/U 30K S/O 30K.;RIH with 4-
1/2" Drill Pipe F/ 661' T/ 3007' P/U 45K S/O 45K Calculated displacement 57.34 BBLs Actual displacement 54.95 BBLs.;Slip and Cut 48' of drilling line. Monitor
well on trip tank.;General housekeeping and maintenance, change out sheaves on mix pumps, change oil in #2 mud pump engine, waiting on barge with liner
running equipment, monitor well on the trip tank.;Clean and organize rig, fix air lines to mud pumps, work on EAM's and preventative maintenance, waiting on
barge with liner running equipment monitor well on trip tank.
9/17/2023 Continue monitoring well on trip tank with 6-3/4" dumb iron cleanout assembly @ 3007' while waiting on barge with Liner Hanger equipment.;Circulate &
condition mud in surface casing @ 3007' GPM 157 SPP 190psi.;RIH with 6-3/4" Cleanout BHA #3 F/ 3007' T/ 4547' with no issues. P/U 72K S/O 43K.;CBU X2
@ GPM 175 SPP 350psi.while reciprocating & rotating @ 60 RPM.;RIH with 6-3/4" Cleanout BHA #3 F/ 4547' T/ 6010' with no issues. P/U 90K S/O 51K.
Calculated displacement 59.7 BBLs Actual displacement 52.03 BBLs.;CBU @ 6010' GPM 160 SPP 754psi RPM 60 TQ 9K P/U 92K S/O 62K ROT 74K max gas
1061 units.;Wash & Ream down F/ 6010 T/ 6841' P/U 94K S/O 64K ROT 76K GPM 136 SPP 540psi. TQ 9-11K RPM 65. Pump Hi-Vis sweep STS came back
16 BBLs early with 40% increase in cuttings. GPM 248 SPP 1316psi. RPM 65 TQ 10K. max gas 2394 units.;Wash & Ream F/ 6841' T/ 7515' P/U 100K S/O 62K
ROT 76K GPM 136 SPP 670psi. TQ 9-13K RPM 65. Pump Hi-Vis sweep STS came back 11 BBLs early with 40% increase in cuttings. GPM 256 SPP 1402psi.
RPM 65 TQ 11K. max gas 1626 units.;Flow check well Static, Pump 18 bbl slug, POOH f/ 7515' t/ 661' L/D BHA, break bit grade 1-1 same as it went in.;R/U
Parker TRS and Liner running equipment on rig floor, PJSM on running liner.;M/U Float equipment baker locking connections, Check Floats good, Continue RIH
w/ 4.5'' Liner as per detail t/ 2213' installing centralizers every other jt.
9/18/2023 Continue RIH w/ 4.5'' 12.6# L-80 Range III TXP/ BTC Liner as per detail F/ 2213' T/ 4642' P/U 59K S/O 47K continuously filling pipe & topping off every ten.
Installing centralizers every other jt.until within 100' of surface shoe. Calculate displacement 16.3 BBLs Actual displacement 16.51 BBLs.;Change out handling
equipment to P/U Liner Hanger. P/U & M/U Liner Hanger as per Baker Rep. Install Pal Mix. R/D TRS equipment & remove from floor. Circulate liner volume @ 5
BPM SPP 300psi.;Continue RIH with Liner running drill pipe from derrick F/ 4675' T/ 7500' filling pipe every 1500'. M/U cement head with 10' pup jt. on bottom
Calculated Displacement 68.2 BBLs Actual displacement 66.3 BBLs.;M/U Top Drive to cement head, Circulate & condition mud for cement job GPM 164 SPP
628psi P/U 98K S/O 70K max gas 928 units. Tag bottom at 7515' park liner at 7513'.;PJSM with all personnel involved for cementing. PT cement lines T 1180psi
low & 4800psi high. Batch up & pump 10.5ppg Spacer @ 3 BPM w/ 420psi, Pump 148 BBLs, 347 sks lead cement, 12ppg, yield 2.389 ft3/sk, WR 5.575 gal/sk,
pumped at 3 BPM w/ 120psi.;Pump 22 BBLs, 99 sks, tail cement, 15.3ppg, yield 1.237 ft3/sk, WR 5.575 gal/sk, pumped at 3 BPM w/ 240psi. Close lower TIW
valve on cement head & open line to cuttings tank. wash up cement from cement pump lines until good water returns seen at tank.;Shut line to cuttings tank &
open lower TIW valve on cement head, Launch drill pipe wiper dart & chase with 10 bbls water @ 3 BPM, DSM observed verification of drill pipe wiper dart
indicator, 102 BBLs 9.4 ppg mud @ 3 BPM starting pressure 500 psi.;observed drill pipe dart catch cement @ 20 bbls & latch liner wiper plug @ 39 bbls away.
FCP 1640psi. Final displacement volume 112 bbls recorded on flex, 108 bbls counted on tanks. Bump plug 500 psi over T/ 2200 psi. floats held, 1 bbl returned to
tanks. CIP@ 17:05.;Pressure up to 2500 psi & observe hanger set. set down & confirm set. Pressure up to set packer a& release running tool. Packer set @
2900 psi. Tool rereleased at 3640 psi. Pressure up to 4000 psi and hold, Bleed off pressure.;L/D cement head, M/U Top Drive & pressure up on pack-off &
release from Liner Hanger clean top of liner GPM 415 SPP 800psi. No losses during job, 30 BBLs spacer & 50 BBLs cement returned to pits.;POOH f/ 2823' t/
surface L/D running tools, clean and clear floor.;P/U stack washer and flush stack, P/U cement head and break off cross overs, P/U jt with pup jt and break off,
R/D cement valves and blow down lines.;M/U polish Mill and RIH on 4.5'' DP t/ 2838' dress off liner top @ 2841'.;Circulate and displace well t/ CI water.;POOH
L/D DP cleaning threads and reinstalling thread protectors L/D polish mill, M/U mule shoe and RIH f/ derrick.
9/19/2023 RIH 33 stands DP, circulated string volume, POOH LD DP, cleaned and doped threads, installed protectors. RIH 32 stands DP, circulated string volume, POOH
LD DP. Cont haul off excess fluid from pits.;Cleaned and cleared rig floor/catwalk, PU jnt with retrieval tool, pulled wear ring. MU wellhead brush, eased down
and flushed/brushed wellhead hanger profile, LD brush and jnt.;RU test pump on kill line, purged air, closed blinds, pumped 2.38 bbls to achieve 3650 psi, held
30 min on chart, good test, bled back 2.38 bbls, RD test equipment. Cont cleaning tank bottoms.;RU TSR equipment, loaded pipe rack with tubing, held
PJSM.;MU Baker 5.750" bullet seal assembly, XO and pup, PU and singled in hole with 12.6# L-80 4 1/2" TXP BTC tubing, torqued to 6170 ft/lbs to 1333'. MU
chem injection mandrel (sn: 24230-01), hung sheave in derrick, installed control line and tested at 2000 psi f/10 min (good).;Cont PU single in from 1333' to
2788', RIH and space out, L/D two jts make p space out pups 3-10' and 1-8' space out 2' off no go and M/U hanger, terminate control lines and land on hanger
test seals and do 40k over pull test.;R/U and test down the tubing t/ 3500 psi f/ 30 min good test, R/U and test down the IA t/ 3500 psi f/ 30 min good test, Bleed
off R/D test equipment, set TWC.;Flush Choke and kill line, choke manifold and gas buster with inhibited water, N/D flow line and bell nipple, N/D choke and kill
lines, open rams doors and inspect, change solid body lowers t/ VBRs, Inspect pump seats and valves.
9/20/2023 Removed koomey lines from stack, RU and hoist BOP stack off wellhead and removed spacer spool. Cleaned last of tank bottoms.;RU and stabbed master
valve on wellhead, bolted up same, wellhead Rep tested hanger neck seals at 5000 psi f/10 min, then tested void/flange at 5000 psi f/10 min. Topped off valve
and tested to 3500 psi f/10 min, all good tests. RD pump skids, undress rig floor.;Checked end play on topdrive quill (ok), C/O swivel packing, installed shipping
blocks in centrifuge and shaker decks, cont loading floats with assorted equipment and ship to J pad, spotted crane and transferred BOP stack from cellar bridge
cranes to cradle, RU and L/D poorboy degasser.;removed cuttings bin and centrifuge, removed kelly hose, service loop and bales, removed torque bushing from
torque tube, staged cradle and removed topdrive from blocks, L/D topdrive, power down service shacks, spooled up cords, loaded and transported shacks to J
pad;RD boiler skid, travel to H pad and lay felt liner and Mats, remove t bar and turn buckles, scope down derrick, remove torque tube and L/D, prep to lay down,
Install shipping beams, clean and clear location. Derrick hand fell into cellar box, sent to camp medic, made notifications.;Hang off blocks, unspool drilling line,
cut off 7 wraps, un pin derrick board, prep to lay over derrick, Secure service loop in derrick, lay down pit rooves, Finish rigging down pumps, pull electrical
cables pason and 37 pin, Lay over derrick, Last report Change AFE to BRU 213-26.
Activity Date Ops Summary
9/24/2023 PJSM, Discuss daily operations,Crew travel to location,Spot in & rig up equipment,Pressure test BOPE 250 low/ 2500 high-good test, perform accumilator draw
down rebuild in 9 seconds all functioning properly.,Cradle coil head and shut in well
9/25/2023 PJSM, Discuss daily coil operations,Crew travel to location,Pick up & make up coil head & lubricator, Make up Yellow J acket 3-3/4" bit on 2-7/8" MM, Test
Lubricator & coil head to 2500 psi-good
Run in hole no fill tag @ 7433',Start pump & displace Drilling mud with clean water.
120 bbls to clean water,Pull out of hole while circulating tubing
Total bbls circulated 180 bbls+/-,Secure well
Pick up coil head & lubricator
Break off bit/ motor/float sub
Stab coil head on cradle
9/26/2023 PJSM, discuss daily wireline operations,Crew travel to location,Spot in & rig up wireline equipment, Pick up & make up tools & surface test-good, Make up
Lubricator & test-250 low, 2500-high-good test,Run in hole with CBL tool assembly, Tag @ 7424' wireline measurement, Log up from tag to surface,Lay down
lubricator, tool string & bope, Secure well,Rig down & prep to move to LRU C-02 in the morning
9/28/2023 PJSM and fill out permits,Pick up and make up injector pressure test to 3000 psi pump N2 online continue in hole tagged at 7430ft. reverse well dry pooh rig
down N2 equipment. Pooh lay down injector.
9/30/2023 Spot E-line equipment lay out lubricator and shut down for night.
10/1/2023 PJSM travel to well site, start and warm up equipment, check tools & arm gun.,P/up Lubricator, stab on well, pressure test lubricator to 250 low and 2500 psi
high,Open well N2 pressure at 1700 psi, RIH with F/N, gun gamma, shock sub, 2-3/4 gun loaded with 11 ft. 6 spf, 60 phasing, run correlation log f/ 7310 ft to 7162
ft. perf the Beluga J-5 sand from 7310 to 7162 ft. Initial pressure 1700 psi. 5-minute reading 1700 psi, 10-minute reading 1700 psi, 15-minute reading 1700 psi
(installed crystal gauge on tree after shooting prefs the analog gauge never moved off 1700 psi, crystal,gauge reading 1600 ps,i pooh with guns, All shots fired,
gun was dry.,Swap out guns check tools arm gun, stab on well, RIH with F/N, gun gamma, shock sub, 2-3/4 gun loaded with24 ft. 6 spf at 60 phasing (OAL 37 ft.
max Od 3.125) Run correlation pass f/ 7030 ft 6831 ft Perf the Beluga J2 sand f/ 6881 ft to 6905 ft. Initial pressure 1571 psi, 5 -minute reading 1573 psi, 10-
minute reading 1571 psi, 15-minute reading 1569 psi pooh with gun all shots fired ,
Gun was dry.,make up gun #3, stab on well RIH with F/n, gun gamma, shock sub, 2-3/4 gun loaded with 6 ft of 6 spf at 60 phasing OAL 18 ft. max od 3.125, run
correlation pas f/ 6757 ft to 6611 ft. Perf the Beluga I 11 sand from 6620 ft to 6626 ft.
Initial pressure at 1530 psi, 5-minute reading 1530 psi, 10-minute reading 1527 psi, 15-minute reading 1525 psi pooh with gun all shots fired gun dry.,ops team
had discussion plan forward see well will flow target pressure 900 psi.
10/2/2023 PJSM, travel to well site start and warm up equipment.,Production venting tbg pressure f/ 1000 psi to 500 psi no LEL present, startup equipment,Check tools, stab
on well, open swab, RIH with F/N weight bar x 3, GPT (OAL 24' MAX OF 2") found fluid level at 6237 ft. To 7200 ft.,Tool quit responding at 7200 ft., trouble shoot
same,Power tool back up, logging up at 60 fpm from 7200 ft. to 5900 ft. Found fluid level at 6137 ft. Pooh close swab,L/ dn GPT tool pressure up to 1000 psi on
tbg with N2, pick up Baker #10 setting tool & 3.71 CIBP.,RIH Log on depth set the 3.71 CIBP at 6595 ELM, pick up off bridge and set back down on same to verify
it set. pooh with setting tool.,Lay down lubricator and crane for night.
10/3/2023 PJSM, travel to location, start and warm up equipment.,Make up tools, stab on lubricator, RIH WITH f/n Gun gamma, shock sub, 2-3/4 gun loaded with 20' spf 60
phasing (OAL 32 ft. max OD3.125") run correlation log f/ 6595' to 5900', pref the Beluga I6 sand f/ 6,418' to 6,438', Initial pressure 989 psi, 5-minute reading 992
psi, 10-minute reading 992 psi, 15- minute reading 993 psi, Pooh, close swab, lay down gun (all shots fired),Make up tools, stab on lubricator, RIH WITH f/n Gun
gamma, shock sub, 2-3/4 gun loaded with 6' spf 60 phasing (OAL 18 ft. max OD3.125") run correlation log f/ 6425' to 6150', pref the Beluga I3 sand f/ 6,318' to
6,324', Initial pressure 990psi, 5-minute reading 990 psi, 10-minute reading 990 psi, 15- minute reading 990 psi, Pooh, close swab, lay down gun (all shots
fired),Make up tools, stab on lubricator, RIH WITH f/n Gun gamma, shock sub, 2-3/4 gun loaded with 4' spf 60 phasing (OAL 18 ft. max OD3.125") run correlation
log f/ 6400' to 6245', pref the Beluga I2 sand f/ 6,300' to 6,304', Initial pressure 994psi, 5-minute reading 995 psi, 10-minute reading 994 psi, 15- minute reading
994 psi, Pooh, close swab, lay down gun (all shots fired),Make up tools, stab on lubricator, RIH WITH f/n Gun gamma, shock sub, 2-3/4 gun loaded with 14' spf 60
phasing (OAL 24 ft. max OD3.125") run correlation log f/ 6400' to 6245', pref the Beluga I2 sand f/ 6,254' to 6,268', Initial pressure 980psi, 5-minute reading 981
psi, 10-minute reading 981 psi, 15- minute reading 982 psi, Pooh, close swab, lay down gun (all shots fired),Make up tools, stab on lubricator, RIH WITH f/n Gun
gamma, shock sub, 2-3/4 gun loaded with 14' spf 60 phasing (OAL 24 ft. max OD3.125") run correlation log f/ 6400' to 6245', pref the Beluga I2 sand f/ 6,254' to
6,268', Initial pressure 980psi, 5-minute reading 981 psi, 10-minute reading 981 psi, 15- minute reading 982 psi, Pooh, close swab, lay down gun (all shots
fired),1Make up tools, stab on lubricator, RIH WITH f/n Gun gamma, shock sub, 2-3/4 gun loaded with 12' spf 60 phasing (OAL 27 ft. max OD3.125") run
correlation log f/ 6400' to 6208', pref the Beluga I2 sand f/ 6,219' to 6,231', Initial pressure 1001 psi, 5-minute reading 1004 psi, 10-minute reading 1004 psi, 15-
minute reading 1004 psi, Pooh, close swab, lay down gun (all shots fired),Rig down for night turn well over to production for t est,
10/4/2023 PJSM Travel to location, start and warm up equipment,Swap out crane and rehead wire, make up GPT with sample bailer..,Work on grease pump,,RIH with GPT
with sampler fluid level at 3,240 ft. continue in hole to 6,250' log up at 150 fpm to surface.,Pressure test lubricator to 250 low & 3,500 psi hi,RIH with GPT while
pressuring up on tbg with N2 to 3,400 psi pushing fluid away, at 1600 hrs. fluid at 4,385 ft.,Pooh with E-line and rig down E=l ine for night,Pressure up to 3,400 psi
on tbg and let sit at 1900 hrs. pressured up on tbg f/ 3,049 psi to 3,400 psi with N2, at 2100 hrs. pressure up on tbg from 3,095 psi to 3400 psi, close tbg with 3400
psi on same secure well for night. Let well sit overnight.,
n (LAT/LONG):
evation (RKB):
50-283-20191-00-00API #:
Well Name:
Field:
County/State:
BRU 241-23
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00092 BRU 241-23 Completion
Spud Date:
10/5/2023 PJSM, travel to well site, start and warm up equipment,RIH with GPT to 6395 ft., found fluid at 6395 ft Pooh, lay down GPT,Pick up 3.75 CIBP RIH, log on depth,
set CIBP at 6204 ELM, pick up off plug and set back tagging to verify it set, Pooh, lay down setting tool,Pick up and RIH with 2-3/4 perf gun loaded with 6' of 6 spf
at 60, log gun on depth, perf the Beluga I sand f/ 6174 to 6180' initial pressure 844 psi, 5-minute reading 845 psi, 10-minute reading 845 psi, 15-minute reading
844 psi, POOH lay down gun (all shots fired),Pick up and RIH with R/S, gun gamma, shock sub, 2-3/4 perf gun load with 20' of 6 spf at 60 OAL 31 ft. Perf the
Beluga, H-15 sand f/ 6091 to 6111; Initial pressure 827 psi, 5-minute reading 834 10-minute reading 835 psi, 15-minute reading 837 psi. Pooh lay down spent gun
all shots fired,Pick up and RIH with GPT to 5915', found fluid at 5915 ft. Pressure up with N2 pushing fluid away. Monitoring fluid level while pressure up to 3300
psi at 900 scfm. fluid level at 6072 ft.,Pick up and RIH with 3.71 CIBP, log on depth, set CIBP at 6070 ft. pooh lay down setting tool,,Secure & Rig down crane for
nights. leave location.
10/6/2023 PJSM, start up and warm up equipment, swap out shooting panel for switch guns.,Make up 2-3/4, perf gun loaded with 8 ft. of 6 spf 60, perf the H8 sand from
5781' to 5789 ft. initial pressure 613 psi, 5-minute reading, 614 psi, 10 -minute reading 612 psi, 15-minute 612 psi pooh lay down gun all shots fired gun dry.,RIH
with single 2-3/4 perf gun load with 2 ft. and 5 ft. 6 spf at 60 phasing perf the H 8 sand f/ 5770 to 5775 ft and 5766 to 5768 ft. initial pressure 606 psi, 5-minute
reading 609 psi, 10-minute reading 611 psi, 15-minute reading 611 psi pooh lay down guns all shots fired gun dry.,RIH with 2-3/4 single 3 ft & 4 ft perf gun load 6
spf at 60 phasing perf the H 5 sand for 5666 to 5670 and 5673 to 5676 ft/ initial pressure 616 psi, 5-minutes reading 618 psi, 10-minute reading 619 psi 15-minute
reading 620 psi pooh lay down gun all shots fired.,RIH with 3 ft and 4 ft 2-3/4 switch gun load with 6 spf, at 60 phasing perf the beluga H 3 sands from 5582 to
5585 ft. initial pressure 629 psi, 5-minute reading 629 psi,10 minutes reading 630 psi, 15-minute reading 681 psi per the H 3 sand from 5569 ft 5573 ft initial
pressure 632 psi 5-minute reading 635 psi, 10- minutes reading psi, 15- minutes reading 635 psi pooh lay down gun all shots fired,RIN with 2-3/4 6' and 3' single
gun load with 6 spf at 60 perf the H2 sand from 5534 ft to 5537 ft. and 5541 ft to 5547 ft. initial pressure 643 psi 5-minute reading 655 psi, 10-minute reading 662
psi and 15-minute reading 669 psi pooh lay down guns all shots fired.,RIH with 6ft 2-3/4 perf gun load with 6spf at 60 phasing perf the H sand f/ 5489 to 5495,
initial pressure 754 psi, 5-minute reading 768 psi, 10-minute reading 777 psi, 15-minute reading 785 psi pooh lay down gun all shots fired.,lay down equipment
and depart location.
10/9/2023 Well online at 300 mcfd @ 280 psi.
Log flowing GPT. FBHP of 580 psi, no fluid in well.
Perforate
Beluga H 5481-5483', 5467-5469'
Beluga G9 5405-5407'
Beluga G5 5286-5292'
No increase in rate or pressure.
Plan forward: continue perforating G sands
10/10/2023 Well online at 300 mcfd @ 280 psi. Perforate G1-G2 sands. No pressure or rate response. Plan Forward: perforate Beluga F sands.
10/11/2023 Continued Ops from previous day.
Well flowing 245 mcfd @ 276 psi.
AK E-line perforated below sands:
Perforated Beluga F10 5124-29', 5116-19', 5105-09', 5076-81'. Rate increase to 350 mcfd and falling.
Perforated Beluga F7 5024-5052'. Rate declining to below 200 mcfd, apparent water entry.
Log flowing GPT, gassed up water above the Beluga F7, heavy water below.
RDMO.
10/17/2023 PJSM, Pre trip & discuss operations,Mob equipment to location, spot in & rig up,Pick up Lubricator & pressure test to 250 low, 2500 high-good test,Pick up & run
in hole with 1.75" X 4' DD bailer to 5720'
Pull out of hole & recover full barrel of grey/muddy sand
Pick up & run in hole with 2.5" x 6' DD bailer to 5739'
Pull out of hole & revovered full barrel grey/muddy sand
Pick up & run in hole with 3" x 8' DD bailer to 5047' slm, sit down, unable to pass
Pull out & recover full barrel
Run in hole with 3" x 8' DD bailer to 5054' slm pull 330lbs over to free,Pull out of hole & recover full barrel
Leaking packing on lubricator
Secure well & rig down to replace packing
Crew travel to camp.
10/18/2023 PJSM, Discuss daily operations,Crew travel to location,Pick up 3.75" gauge ring unable to pass thru wellhead
Pull out of hole
Pick up 1.75" DD bailer run in hole to 5500 slm
Work thru tight spots in & out of hole
Decsion made to rig down & do coil clean out
Secure well rig down & desand tools & equipment
Page 1/3
Well Name: BRU 241-23
Report Printed: 12/12/2023www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:9/24/2023 End Date:
Report Number
18
Report Start Date
10/20/2023
Report End Date
10/21/2023
Operation
PJSM, Discuss Coil mob & clean out operations
Crew travel to location
Mob equipment & tanks to location
Spot in Rig up & Nipple up bope Function & test-good
Fill BOP & pressure test BOPE 250 low/2500 high-good
Transfer N2 rig up lines & fluid pump, Spot in & rig up N2 pump & lines, Winterize equipment , Secure well
End of day
Report Number
19
Report Start Date
10/21/2023
Report End Date
10/22/2023
Operation
PJSM, Discuss Coil clean out operations
Crew travel to location, check wellhead pressure 1200 psi.
Pick up injection head & lubricator, Make up motor & 3.75" & test-good, Pressure test 250 low/3000 high for stripping head & Lubricator-good
Run in hole with coil tubing & motor @ 1 gpm @ 2489 psi work thru wellhead. 1270' tag medium to firm bridge work thru, Clean out to 5500', well head pressure
1212 psi
Pull out of hole circulating
Remove injector head & lay down motor, Make up injector & lubricator, Blow string dry & choke, Trap 1275 psi in wellbore (injecting @ 1275'), Rig down
Rig up Eline over coil BOPE pressure test 250 low/ 3000 high
Run in hole with CBL/GR/Plug (3.71") Tag @ 5028', Pull strip & corrolate, adjust -1, Getting on setting depth @ 5000' (CCL depth 4986'), Pick up & tag plug to
confirm-good
Secure well & lay down Lubricator & bops
End of Day
Pull out of hole with E-line
Report Number
20
Report Start Date
10/22/2023
Report End Date
10/23/2023
Operation
PJSM, Discuss Coil clean out operations
Crew travel to location
Pick up injection head & lubricator, Make up circulation head & test-good, Run in hole to 5000' tag pick up 3'
Circulate hole dry (recover 45 bbls)
Rig down coil injection head, Nipple down bope, nipple up running flange
Pick up & make up 5 ft & 4 ft gun, Pick up & install lubricator pressure test to 250 low/3000 high-good test.
Run in the hole with 5 ft x 2-3/4", (6 spf, 15 grams) & 4' X 2-3/4" (6 spf, 15 grams) CCL-TS for 5' shot: 16' (Beluga E6 4685'-4690') Correlate & get approval CCL @
4669' (0 min-550 psi, 5 min-650 psi, 10 min-800 psi, 15 min-900 psi
After firing tool string was light 400 lbs, coming out of hole pull tight 4669 to 3885'. Pull tension @ 418'. Close Wireline bops bleed off lubricator & strip wire thru
bops. Cut line with swab valve & rig down.
End of day
Report Number
21
Report Start Date
10/23/2023
Report End Date
10/24/2023
Operation
PJSM, Discuss Coil clean out operations
Crew travel to location.
E-line crew clean out lubricator & grease tubes, clear 30' +/-
PJSM, Mob equipment from D pad to K pad, Spot in & rig up equipment.
Pressure test lubricator 250-low/2500-high, good test
Pick up & run in hole 2.5" JUS w/ baited wire finder with 3 prong grab (3.8" OD) to 1" SLM Pull out of hole with extra 20lbs shut in swab
Bleed off and attempt to jar tools out of lubricator (unable), Break lubricator down & retrieve 20' +/- of line
Pick up & run in hole with 2.5" jus baited wirefinder with 2 prong grab 2.9" OD to 3572' slm, Pull out of hole empty
API: 5028320191 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:Permit to Drill (PTD) #:223061
Page 2/3
Well Name: BRU 241-23
Report Printed: 12/12/2023www.peloton.com
Well Operations Summary
Operation
Pick up & run in hole with 2.5" jus baited wirefinder with bell guide (3.65" OD) to 3572', Jar down multiple times come out of hole, sheared tools.
Pick up & dress with over shot & run in hole to tag @ 3547' Jar up & come out of hole, Retrieved tools & hanful of wire.
Secure well & rig down
End of day
Report Number
22
Report Start Date
10/24/2023
Report End Date
10/25/2023
Operation
PJSM, Discuss slick line operations
Crew travel to location.
Pick up 3.73" LIB & lubricator Pressure test 250 low, 2500 high good test
Run in hole & tag @ 3553' slm, Pull out of hole, Small wire imprints on face
Pick up & run in hole with 2.5" JUS with 1.75" baitsub with 3.8" wirefinder with 3 prong wire grab (2.62" spread to 3.8") 3554' slm, work tool, minimal overpull, pull
out of hole retrieve 7'
Pick up & run in hole with 2.5" JUS with 1.75" baitsub with 3.8" wirefinder with 3 prong wire grab (2.62" spread to 3.8") 3555' slm, work tool, minimal overpull, pull
out of hole no fish
Pick up & run in hole with 2.5" JUS with 1.75" baitsub with 3.8" wirefinder with 2 prong wire grab (2.1" OD with 2 prongs) 3551' slm work tool, see drag 3542', Slip
off, Work tools, Pull out of hole, No fish
Add 5' stem above jars, Check JU pin, Change out wire grab
Pick up & run in hole with 2.5" JUS with 1.75" baitsub with 3.8" wirefinder with 3 prong wire grab (3.8" short grab) 3553' slm work too down to slm, No bites Work
tools, Pull out of hole pin sheared, no fish
Pick up & run in hole with 2.5" JDC with 3.62" bell guide to 3555' slm latch bait, Jar up (5 times), Pull out of hole, Sheared pin, No fish
Pick up & run in hole with 2.5" JDC with 3.62" bell guide to 3555' slm latch bait, Jar string up to 3484',
lay down lub slip 100' of line check all connections
Pick up & run 2.5" JDC w/ 3.62" bell guid to 3489 slm, Jar multiple times come out of hole with 22' of wire
Pick up 2.5" JUS w/ baited wire finder & 2 prong to 3524' work until shear, Pull out of hole
Pick up 2.5" JDC w/ baited wire finder & bell guide to 3548' work until shear, Pull out of hole
Pick up 2.5" JDC w/ baited wire finder & bell guide to 3548' work until shear, Pull out of hole
End Of day
Report Number
23
Report Start Date
10/25/2023
Report End Date
10/26/2023
Operation
Shut in Wireline valves, break off lube & install clamp on breaded line, Lay down tool string, Cut & strip line, reinstall lube
Rig Down Lubricator & secure well
End of day
Report Number
24
Report Start Date
10/26/2023
Report End Date
10/26/2023
Operation
PJSM, DISCUSS DAILY OPERATIONS & FISHING WITH SLICK LINE
TRAVEL TO LOCATIONS
PICK UP LUBRICATOR & LIB, STAB LUBRICATOR & PRESSURE TEST TO 250 LOW/2500 HIGH-PASS
RUN IN HOLE WITH 3.73" LIB 3527' SLM, PULL OUT OF HOLE AND INSPECT (CABLE IMPRESSIONS)
PICK UP 2.5" JUS W/ 1.75" BAIT SUB & 3.8" WIREFINDERW/ 2 PRONGS WIRE GRAB (1.75") TAG @ 3527', CHASE CABLE TO 4831' SLM, WORK STRING &
PULL OUT OF HOLE. (RECOVERED 9' OF LINE)
RUN IN HOLE WITH 3.78" LIB TO TAG @ 4831', PULL OUT OF HOLE & INSPECT LIB ( IMPRESSIONS OF SAND)
PICK UP & RUN IN HOLE WITH 2 PRONG WIREFINDER TO TAG @ 4831', PULL OUT OF HOLE & SHEARED WIRE FINDER
PICK UP & MAKE UP BELL GUIDE & RUN IN HOLE TO TAG @ 4831' ATTEMPT TO LATCH ON SHEARED, PULL OUT OF HOLE AND REPIN RUN BACK IN
HOLE WITH BELL GUIDE AND RETRIEVE 2 PRONG. PULL OUT OF HOLE.
SHUT IN & SECURE, RIG DOWN SLICK LINE EQUIPMENT & TOOLS. FLOW WELL.
Report Number
25
Report Start Date
11/10/2023
Report End Date
11/11/2023
API: 5028320191 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:
Page 3/3
Well Name: BRU 241-23
Report Printed: 12/12/2023www.peloton.com
Well Operations Summary
Operation
Report Number
26
Report Start Date
11/11/2023
Report End Date
11/12/2023
Operation
Report Number
27
Report Start Date
11/24/2023
Report End Date
11/25/2023
Operation
Crew travel to Beluga, Mob equipment from D-pad to location, PJSM, Spot in & rig up equipment, Test all tools & equipment.
Report Number
28
Report Start Date
11/25/2023
Report End Date
11/26/2023
Operation
PJSM, Discuss daily operations, Crew travel to location, Rig up, PIck up lubericator & 4' gun, Swedge up on wellhead & pressure test 250 low/3000 high-good, Run
in hole to perform correlation pass-adjust depth, PIck up to perf depth, CCL-TS=15.3', perfs f/ 4616'-4620', (OG-1440, 5-1477, 10-1515, 15-1535), Pull out of hole &
pick up gun #2, Run in hole & get on depth, CCL-TS-13.5', Perf f/ 4603' to 4609', (OG psi, 1612, 5-1614, 10-1605, 15-1600), Pull out of hole & rig down. Mob to J-
pad
API: 5028320191 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:
Cost Only
Cost Only
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AE A
A
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.09.28 08:57:13 -08'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.09.28 09:23:00 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
72
Yes X No Yes X No 30
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Type I II 427 2.44
Type I II 173 1.16
4
23.67
Hanger 13 5/8 BTC 1.26 23.67 22.41
2,963.36 27.99
Pup 7 5/8 29.7 L-80 TXP BTC Tenaris 4.32 27.99
1.43 2,964.79 2,963.36
Casing 7 5/8 29.7 L-80 TXP BTC Tenaris 2,935.37
Float collar 8 5/8 BTC Innovex
Ran 36 Hydro form centralizers.
Casing 7 5/8 29.7 L-80 TXP BTC Tenaris 82.88 3,047.67 2,964.79
www.wellez.net WellEz Information Management LLC ver_04818br
4
Type of Shoe:Innovex Casing Crew:Parker
12 190
3,049.273,059.00 2,963.36
CEMENTING REPORT
Csg Wt. On Slips:27,000
Spud Mud
14:35 9/9/2023 Surface
15.8 33
Bump press
Visual
Bump Plug?
132/136
1300
87
HES
FI
R
S
T
S
T
A
G
E
10.5Tune 60
9.4 4
100
690
Csg Wt. On Hook:42,000 Type Float Collar:Innovex No. Hrs to Run:8.5
BTC Innovex 1.60 3,049.27 3,047.67
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 241-23 Date Run 9-Sep-23
CASING RECORD
County State Alaska Supv.J Murphy / J Richardson
2,963.36
Floats Held
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 3049.27 FC @ Top of Liner
Casing (Or Liner) Detail
Shoe 8 5/8
TD Shoe Depth: PBTD:
Jts.
1
1
111
Yes No X Yes No
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?:X Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Float Shoe 5 12.6 L-80
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 7513 FC @ Top of Liner 2840.597,470.00
Floats Held3500
6% KCL Polymer
CASING RECORD
County State Alaska Supv.J Murphy / J Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 241-23 Date Run 18-Sep-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC JHOBBS 1.82 7,513.00 7,511.18
Csg Wt. On Hook: Type Float Collar:JHOBBS No. Hrs to Run:12
9.4 3
100
1640
FI
R
S
T
S
T
A
G
E
10.5Tune Primed 30
112/114
2200
50
Halliburton
15.3 22
Bump press
CBL
Bump Plug?
17:06 9/18/2023 2850'
7,513.007,515.00
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL Polymer
12 148
Type of Shoe:JHOBBS Casing Crew:Parker
Baker ZXP FLEX
www.wellez.net WellEz Information Management LLC ver_04818br
3
4.5' Liner JT 4 1/2 12.6 L-80 BTC 41.50 7,511.18 7,471.50
Float Collar 5 12.6 L-80 BTC 1.31 7,471.50 7,470.19
4.5'' Liner Jt 4 1/2 12.6 L-80 BTC 39.68 7,470.19 7,430.51
Landing Collar 5 12.6 L-80 BTC 1.08 7,430.51 7,429.43
4.5'' Liner jts 4 1/2 12.6 L-80 TXP 7,429.43 2,873.04
Liner Hanger ZXP RS Flex 7 5/8 TXP Baker 32.45 2,873.04 2,840.59
l ll 347 2.39
l ll 99 1.24
3
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/01/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231101
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 10/10/2023 AK E-LINE Perf
BRU 241-23 50283201910000 223061 10/21/2023 AK E-LINE Plug/Perf
BRU 242-04 50283201640000 212041 10/13/2023 AK E-LINE Perf/PL
KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/Perf
MPU L-62 50029236850000 220059 10/18/2023 HALLIBURTON MFC24
PBU 06-20B 50029207990200 223075 10/19/2023 HALLIBURTON RBT
PBU W-26A 50029219640100 199081 12/16/2022 AK E-LINE CBL
Please include current contact information if different from above.
T38113
T38113
T38114
T38115
T38116
T38117
T38118
11/1/2023
BRU 241-23 50283201910000 223061 10/10/2023 AK E-LINE Perf
BRU 241-23 50283201910000 223061 10/21/2023 AK E-LINE Plug/Perf
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.11.01
14:36:12 -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: 10/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231025
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 9/27/2023 AK E-LINE CBL
BRU 241-23 50283201910000 223061 10/4/2023 AK E-LINE GPT/Plug/Perf
GP ST 18742 37 50733203940000 187109 9/30/2023 AK E-LINE Plug
IRU 41-01 50283200880000 192109 9/22/2023 AK E-LINE Perf/GPT
LRU C-02 50283201900000 223057 9/28/2023 AK E-LINE Perf
LRU C-02 50283201900000 223057 9/25/2023 AK E-LINE Perf/GPT
MPU K-13 50029226550000 196040 10/1/2023 AK E-LINE GPT/Plug/Perf
NCI A-05 50883200250000 169032 9/27/2023 AK E-LINE Perf
Please include current contact information if different from above.
T38097
T38097
T38098
T38099
T38100
T38100
T38101
T38102
10/25/2023
BRU 241-23 50283201910000 223061 9/27/2023 AK E-LINE CBL
BRU 241-23 50283201910000 223061 10/4/2023 AK E-LINE GPT/Plug/Perf
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.10.25
11:33:48 -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:Jacob Flora
Subject:RE: BRU 241-23 AOGCC 10-403 323-526 PTD 223-061 - CBL for approval
Date:Monday, October 2, 2023 4:22:00 PM
Attachments:image004.png
image005.png
Jake,
Hilcorp has approval to proceed with perforating per sundry 323-526.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, October 2, 2023 3:10 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: BRU 241-23 AOGCC 10-403 323-526 PTD 223-061 - CBL for approval
Hi Bryan,
Please see attached CBL. The TOC is right at the liner top packer at ~2850’.
Thanks,
Jake
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Tuesday, September 26, 2023 1:16 PM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Yarawsky, Sharon <syarawsk@blm.gov>
Subject: BRU 241-23 AOGCC 10-403 323-526 PTD 223-061 Approved 09-26-23
FYI – Please distribute as necessary.
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
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: 9/27/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 241-23
- PTD 223-061
- API 50-283-20191-00-00
FINAL LWD FORMATION EVALUATION LOGS (09/06/2023 to 09/16/2023)
ROP, AGR, PCG, EWR-M5, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-061
T38016
9/28/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.09.28
08:48:50 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 09/27/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 241-23
- PTD 223-061
- API 50-283-20191-00-00
MUDLOGS - EOW DRILLING REPORTS (09/06/2023 to 09/16/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log
Drilling Dynamics Log
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-061
T38015
9/27/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.09.27
15:13:17 -08'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, CTCO, 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):
7,515'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
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
LTP; N/A 2,846' MD/ 2,533' TVD; N/A, N/A
7,161'7,429'7,075'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 241-23CO 802
Same
7,075'4-1/2"
~2,368psi
4,591'
N/A
Length
October 4, 2023
Tieback
7,429'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
3,049'
Size
120'
3,949'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
2,846'
8,430psi
2,799'
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
ADL0021128
223-061
50-283-20191-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
jake.flora@hilcorp.com
907-777-8442
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
Ot
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:30 pm, Sep 22, 2023
323-526
Digitally signed by Aras
Worthington (4643)
DN: cn=Aras Worthington (4643)
Date: 2023.09.21 10:56:11 -
08'00'
Aras
Worthington
(4643)
Perforate
X
CT BOP test to 2500 psi
10-407
SFD 9/25/2023BJM 9/22/23
Yes - for steps 1-7 only 9/22/23
Bryan McLellan
Submit CBL to AOGCC and obtain approval before perforating.
DSR-9/25/23*&:
09/26/23
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.09.26 10:57:22
-08'00'
RBDMS JSB 092723
Well Prognosis
Well Name: BRU 241-23 API Number: 50-283-20191-00-00
Current Status: Gas Producer Permit to Drill Number: 223-061
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Second Call Engineer: Chad Helgeson (907) 229-4824 (C)
Maximum Expected BHP: 3006 psi @ 6834’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2368 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 241-23 is the third of five grass roots wells planned to be drilled in the 2023 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:
Drilling will leave the cemented 4.5” liner full of drilling mud, with the 4.5” tubing and annulus displaced to KCL,
and pressure tested.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 2500 psi. higher test pressure to accommodate reverse out
4. Clean out wellbore to TD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, PT lubricator to 2500psi, log CBL submit CBL to AOGCC for review
6. RIH, reverse out wellbore with nitrogen, trap ~1700 psi on wellbore (recover 113 bbls)
7. RDMO coil tubing
8. RU E-line, PT lubricator to 2500 psi
9. Perforate and test Beluga sands within the interval below, from the bottom up:
Sand MD TVD
Top Sand Beluga F 4741’ 4427’
Bottom Sand Beluga J 7185’ 6834’
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 13.64 ppg EMW FIT at the surface casing shoe (0.709 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.709-0.1) = 2368 psi / 0.609 = 3888‘ TVD
10. RDMO
11. Turn well over to production & flow test well
Contingencies:
= 3888‘ TVD
OK.
Well Prognosis
Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating):
1. MIRU Coiled Tubing, notify AOGCC 48 hours in advance of BOP test, PT BOPE to 2500 psi
2. Clean out to TD (or desired depth by engineer)
3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
Updated by CAH 09-19-23
CURRENT SCHEMATIC
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,838’ 7,429’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,846’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ~1,500’ 3.958” 4.500” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) of lead 12.0 ppg (14.4 gal/sx)followed by 173 sx (33 bbls) of 15.8
ppg tail (5.08 gal/sx) – returned all spacer and 87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) of lead 12 ppg followed by 99sks (22 bbls) of 15.3 ppg tail cement.
Bumped plug and circulated 50 bbls of cement off liner top. Est. TOC @ TOL
6-3/4”
hole
2
1
Updated by CAH 09-19-23
PROPOSED
Beluga River Unit
BRU 241-23
PTD: 50-283-20191-00-00
API: 223-061
PBTD = 7,429’ / TVD = 7,075’
TD = 7,515’ / TVD = 7,161’
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 TXP 6.875” Surf 3,049’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,838’ 7,429’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,846’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ~1,500’ 3.958” 4.500” Chemical Injection Sub
2 2,846’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8" 427 sx (190 bbls) of lead 12.0 ppg (14.4 gal/sx) followed by 173 sx (33 bbls) of 15.8
ppg tail (5.08 gal/sx) – returned all spacer and 87 bbls of cement. TOC @ Surface
4-1/2” 347 sx (148 bbls) of lead 12 ppg followed by 99sks (22 bbls) of 15.3 ppg tail cement.
Bumped plug and circulated 50 bbls of cement off liner top. Est. TOC @ TOL
6-3/4”
hole
2
1
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel F-J ±4,741’ ±7,185’ ±4,427’ ±6,835’ 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.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Chad Helgeson
Subject:RE: [EXTERNAL] RE: BRU 241-23 AOGCC 10-403 PTD 223-061 Submitted 09-21-23 - Sundry Application
Date:Friday, September 22, 2023 2:58:00 PM
Attachments:image004.png
image005.png
Jake,
Hilcorp has approval to proceed with steps 1-7 below.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Friday, September 22, 2023 1:52 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>
Subject: FW: [EXTERNAL] RE: BRU 241-23 AOGCC 10-403 PTD 223-061 Submitted 09-21-23 - Sundry
Application
Hi Bryan,
Can we get a verbal to proceed with the post rig coil cleanout steps 1-7 as detailed below?
From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Sent: Friday, September 22, 2023 1:37 PM
To: Donna Ambruz <dambruz@hilcorp.com>
Cc: Chad Helgeson <chelgeson@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Noel Nocas <Noel.Nocas@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Subject: [EXTERNAL] RE: BRU 241-23 AOGCC 10-403 PTD 223-061 Submitted 09-21-23 - Sundry
Application
Received for processing.
Thank you,
Grace Christianson
Executive Assistant, AOGCC
(907) 793-1230
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Thursday, September 21, 2023 11:07 AM
To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>;
Noel Nocas <Noel.Nocas@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: BRU 241-23 AOGCC 10-403 PTD 223-061 Submitted 09-21-23 - Sundry Application
Application for Sundry Approval
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1
Regg, James B (OGC)
From:Joshua Riley - (C) <jriley@hilcorp.com>
Sent:Wednesday, September 20, 2023 4:38 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MITT BRU 243-21 Rig 147 9-20-23
Attachments:BRU 241-23 MITT.XLSX
Here is the MITT for BRU 241‐23 thank you
Josh Riley
Hilcorp DSM: 907-283-1369
Cell: 907-252-1211
Hilcorp Alaska, LLC
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Beluga River Unit 241-23PTD 2230610
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-061 Type Inj N Tubing 3600 3600 3600 Type Test P
Packer TVD 2841 BBL Pump 1.4 IA 90 90 90 Interval O
Test psi 3500 BBL Return 1.4 OA 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-061 Type Inj N Tubing 290 290 290 Type Test P
Packer TVD 2841 BBL Pump 1.2 IA 3600 3600 3600 Interval O
Test psi 3500 BBL Return 1.2 OA 0 0 0 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:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:MITT of tubing and IA after completion string ran
Notes:
Notes:
Hilcorp
Beluga River Unit K pad
None
Josh Riley
09/20/23
Notes:MITT of tubing and IA after completion string ran
Notes:
Notes:
Notes:
BRU 241-23
BRU 241-23
Form 10-426 (Revised 01/2017)2023-0920_MITP_BRU_241-23_2tests
jbr
J. Regg; 12/13/2023
MITIA
================jbr
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 Field, Sterling-Beluga Gas Pool, BRU 241-23
Hilcorp Alaska, LLC
Permit to Drill Number: 223-061
Surface Location: 2162’ FNL, 60’ FWL, Sec 24, T13N, R10W, SM, AK ADL 21128
Bottomhole Location: 374' FNL, 752' 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,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of August 2023. 9
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.09 13:15:19
-08'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 7,451' TVD: 7,097'
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): 96.6 15. Distance to Nearest Well Open
Surface: x-323392 y- 2633474 Zone-4 78.1 to Same Pool:1592' to BRU 214-13
16. Deviated wells:Kickoff depth: 350 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 28 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 TXP 3,057' Surface Surface 3,057' 2,807'
6-3/4" 4-1/2" 12.6# L-80 TXP 4,593' 2,857' 2,628' 7,450' 7,097'
Tieback 4-1/2" 12.6# L-80 TXP 2,857' Surface Surface 2,857' 2,628'
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
8/15/2023
2536' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
907-777-8413
Tieback Assy.
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):
Production
Liner
Intermediate
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 1025 ft3 / T - 182 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
489
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 - 812 ft3 / T - 104 ft3
2415
1202' FNL, 365' FEL, Sec 23, T13N, R10W, SM, AK
374' FNL, 752' FEL, Sec 23, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
2162’ FNL, 60’ FWL, Sec 24, T13N, R10W, SM, AK ADL 21128
BRU 241-23
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
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Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
7.12.2023
By Grace Christianson at 1:59 pm, Jul 12, 2023
Drilling Manager
07/12/23
Monty M
Myers
50-283-20200-00-00
A.Dewhurst 07 AUG 2023
223-061
BJM 8/9/23
BOP test to 3500 psi. Annular test to 2500 psi.
DSR-7/12/23
Submit FIT/LOT results within 48 hrs of performing test.
GCW 08/09/2023JLC 8/9/2023
08/09/23
08/09/23
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.08.09 13:15:33 -08'00'
50-283-20191-00-00
corrected API 9/5/2023 MDG
BRU 241-23
Drilling Program
Beluga River Unit
Rev 0
July 5, 2023
BRU 241-23
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.....................................................................................................11
10.0 N/U 21-1/4” 2M Diverter .........................................................................................................12
11.0 Drill 9-7/8”Hole Section..........................................................................................................14
12.0 Run 7-5/8” Surface Casing ......................................................................................................16
13.0 Cement 7-5/8” Surface Casing.................................................................................................19
14.0 BOP N/U and Test....................................................................................................................22
15.0 Drill 6-3/4” Hole Section ..........................................................................................................23
16.0 Run 4-1/2” Production Liner ...................................................................................................26
17.0 Cement 4-1/2” Production Liner .............................................................................................29
18.0 4-1/2” Liner Tieback Polish Run .............................................................................................32
19.0 4-1/2” Tieback Run, ND/NU, RDMO ......................................................................................33
20.0 Diverter Schematic ..................................................................................................................34
21.0 BOP Schematic ........................................................................................................................35
22.0 Wellhead Schematic.................................................................................................................36
23.0 Days Vs Depth..........................................................................................................................37
24.0 Geo-Prog..................................................................................................................................38
25.0 Anticipated Drilling Hazards ..................................................................................................39
26.0 Hilcorp Rig 147 Layout ...........................................................................................................41
27.0 FIT/LOT Procedure.................................................................................................................42
28.0 Choke Manifold Schematic......................................................................................................43
29.0 Casing Design Information......................................................................................................44
30.0 6-3/4” Hole Section MASP .......................................................................................................45
31.0 Spider Plot w/ 660’ Radius for SSSV.......................................................................................46
32.0 Surface Plat (As-Built NAD27)................................................................................................47
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1.0 Well Summary
Well BRU 241-23
Pad & Old Well Designation BRU F Pad –Grassroots Well
Planned Completion Type 4-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7,450 MD / 7,097’ TVD
PBTD, MD / TVD 7,370’ MD / 7,018’TVD
Surface Location (Governmental)2162’ FNL, 60’ FWL, Sec 24, T13N, R10W, SM, AK
Surface Location (NAD 27)X=323392.31 Y=2633474.26
Top of Productive Horizon
(Governmental)1202' FNL, 365' FEL, Sec 23, T13N, R10W, SM, AK
TPH Location (NAD 27)X=322984.49, Y=2634435.00
BHL (Governmental)374' FNL, 752' FEL, Sec 23, T13N, R10W, SM, AK
BHL (NAD 27)X=322609.69, Y=2635268.90
AFE Number
AFE Drilling Days 23
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2415 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3125 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 96.6’(78.1 + 18.5)
Ground Elevation 78.1’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
A. Dewhurst
07 AUG 2023
K-Pad
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Drilling Procedure
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2.0 Management of Change Information
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BRU 241-23
Drilling Procedure
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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 L-80 TXP 6890 4790 683
Prod
6-3/4”4-1/2”3.958”3.833”5.000”12.6 L-80 TXP 8430 7500 288
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
Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k
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 Wellez.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area –this will not save the data entered, and will navigate to another data entry
tab.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a
username to login with.
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. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
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 mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@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 241-23 is an S-shaped directional grassroots development well to be drilled from BRU K 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 ~350’MD. Maximum hole angle
will be ~29 deg. and TD of the well will be 7,450’ TMD/ 7,097’ TVD, ending with 10 deg inclination left in
the hole.
Drilling operations are expected to commence approximately August 15th, 2023. The Hilcorp Rig # 147 will
be used to drill the wellbore then run casing and cement.
Surface casing will be run to 3,057 MD / 2,807’ 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) will be run to 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 to haul cuttingsto the Kenai Gas Field G&I facility for disposal / beneficial
reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 147 to well site
2. N/U diverter and test.
3. Drill 9-7/8”hole to 3,057’ MD. Run and cmt 7-5/8”surface casing.
4. ND diverter, N/U & test 11” x 5M BOP.
5. Drill 6-3/4” hole section to 7,450’MD. Perform Wiper trip.
6. Make cleanout run
7. POOH laying down drill pipe.
8. Run and cmt 4-1/2”production liner.
9. PU clean out assembly and RIH to clean out 4-1/2”to landing collar
10. Displace well to completion fluid.
11. POOH and LD clean out assembly.
12. RIH and land 4-1/2” tieback string in liner top.
13. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo + Pressures MWD
x pressures dependent on hole conditions
Mud loggers from surface casing point to TD.
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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 241-23. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/5000 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the PTD.
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 permit is 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.
Regulation Variance Requests:
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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: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(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 spud.
x 48 hours notice prior to testing BOPs.
x 48 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Additional requirements may be stipulated on PTD.
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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)
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9.0 R/U and Preparatory Work
9.1 16” conductor set at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with
flowline later.
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 RU Mud loggers on surface hole section for gas detection only. No samples required
9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.9 Mix mud for 9-7/8”hole section.
9.10 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.
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10.5 Rig 147 and estimated Diverter line orientation on BRU K 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. Hydraulics
calculations and recommended TFA is attached below.
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 3,057’MD/ 2,807’ 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. Coal seam log will be
provided by Hilcorp Geo team.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 500’ 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 between 2900’ MD and 3100’ MD.
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
120-3,057’ 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 Weatherford 7-5/8”casing running equipment.
x Ensure 7-5/8”TXP 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 M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values
required to achieve this position.
x After making up several connections, use the torque required to M/U to base of triangle as
the M/U torque and continue running string.
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.
7-5/8” 29.7# TXP M/U torques
Casing OD Minimum Maximum Yield Torque
7-5/8”15,970 ft-lbs 19,510 ft-lbs 24,200 ft-lbs
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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% open hole excess for lead and 50% open hole
excess for tail. Job will consist of lead & tail, TOC brought to surface.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
16”Conductor x 7-5/8”
casing annulus:
120’ x .16239 bpf =19.49 109.4
12.0 ppg LEAD:
9-7/8”OH x 7-5/8”Casing
annulus:
(2557’ –120’) x .03825 bpf x
1.75 =
163.13 915.9
Total LEAD:182.62 bbl 1025.3 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(3057’- 2557’)x .03825 bpf x
1.5 =
28.69 161.1
15.4 ppg TAIL:
7-5/8”Shoe track:
80 x .04592 bpf =3.67 20.6
Total TAIL:32.36 bbl 181.7 ft3
TOTAL CEMENT VOL:214.98 bbl 1207.0 ft3
Verified cement volumes. -bjm
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Cement Slurry Design:
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 Displacement calculation:
3057’-80’ = 2977’x .04592 bpf = 137 bbls
13.12 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.
13.13 Do not overdisplace by more than ½ 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 us to run steel pipe through the hanger flutes. The ID of the flutes
is 1.5”.
13.14 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.
13.15 R/D cement equipment. Flush out wellhead with FW.
13.16 Back out and L/D landing joint. Flush out wellhead with FW.
Lead Slurry (2557’ MD to surface)Tail Slurry (3057’ to 2557’ 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
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13.17 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.
13.18 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
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
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U wellhead assy. Test to 5000 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 Run 4-1/2”BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/5 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.0 ppg 6% KCL PHPA mud system.
14.8 R/U mud loggers for production hole section.
14.9 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. Hydraulics
calculations and recommended TFA is attached below.
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
3,057’-7,450’9.0 –10.0 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 –10.0 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.
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” burst is 6880 psi / 2 = 3440 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 13.4 ppg EMW. Send the FIT results to the AOGCC within 24 hrs.
Note: Offset field test data predicts frac gradient at the 7-5/8”shoe to be between 11 - 15 ppg
EMW. A 13.4 ppg FIT results in a > 15 bbl kick tolerance volume while drilling with the
planned MW of 10.0 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
15.14 Drill 6-3/4” hole section to 7,450’ MD / 7,097’ 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 On the third wiper trip (around 5,300’ MD), trip back to the 7-5/8” shoe (LL from 224-24) to
split the hole section in half.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Watch for lost circulation when drilling through Beluga D through F (4,134-5,134’ MD).
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.
x Take (3) sets of formation samples every 20’.
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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.
15.17 LD BHA
15.18 If not acquired in previous BHA run, PU GeoTap BHA. RIH and perform pressure sampling per
geologist.
15.19 When pressure sampling complete, RIH to TD. Pump sweep, CBU and condition mud for casing
run.
15.20 POOH LDDP and BHA
15.21 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
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16.0 Run 4-1/2”Production Liner
16.1. R/U Weatherford 4-1/2”casing running equipment.
x Ensure 4-1/2”TXP BTC 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 4-1/2”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 across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 4-1/2” production liner
4-1/2” 12.6# TXP M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”5,550 ft-lbs 6,170 ft-lbs 6,790 ft-lbs
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16.6. Run in hole w/ 4-1/2” 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 4-1/2” 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 4-1/2”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.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” liner
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
6-3/4” OH x 4-1/2” annulus:
(6950’ –3057’) x .02459 bpf x
1.4 =
134.02 752.5
Total LEAD:144.52 bbl 811.5 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(7450’- 6950’) x .02459 bpf x
1.4 =
17.21 96.6
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf =1.22 6.8
Total TAIL:18.43 bbl 103.5 ft3
TOTAL CEMENT VOL:162.95 bbl 915.0 ft3
Verified cement calcs. -bjm
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Cement Slurry Design:
Lead Slurry (6950’ MD to 2857’ MD)Tail Slurry (7450’ to 6950’ 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
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 latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
17.9. If elevated displacement pressures are encountered, position casing 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 ½ shoe track. Shoe track volume is 2 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).
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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.
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 wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
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
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 4-1/2”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.
x NOTE: If a cleanout run inside the 4-1/2” is needed, BOPs need to be tested with 2-7/8” test
joint to cover cleanout assembly.
18.4. If not completed, test 4-1/2” casing to 3,500 psi and chart for 30 minutes
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19.0 4-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 DWC/C-HT casing. Ensure any
jewelry is picked up per tally.
4-1/2” 12.6# TXP M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”5,550 ft-lbs 6,170 ft-lbs 6,790 ft-lbs
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 4-1/2” liner and tieback to 3,500 psi and chart for 30 minutes. 48 hr notice required.
19.7 Test 7-5/8” x 4-1/2” annulus to 2,500 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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21.0 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Geo-Prog
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25.0 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 insure 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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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.
While losses haven’t been observed from K-Pad, given the volume of losses experienced in the wells on
and surrounding F-Pad, 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.
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26.0 Hilcorp Rig 147 Layout
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27.0 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.
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28.0 Choke Manifold Schematic
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29.0 Casing Design Information
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30.0 6-3/4” Hole Section MASP
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31.0 Spider Plot w/ 660’ Radius for SSSV
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32.0 Surface Plat (As-Built NAD27)
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!""#
$
%
&
0
475
950
1425
1900
2375
2850
3325
3800
4275
4750
5225
5700
6175
6650
7125
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t
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0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175 6650
Vertical Section at 336.00° (950 usft/in)
BRU 241-23 wp07 tgt1
16" Casing
7 5/8" x 9 7/8"
4 1/2" x 6 3/4"
5 00
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 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 4 5 1
BRU 241-23 wp07
Start Dir 3º/100' : 350' MD, 350'TVD
End Dir : 1303.24' MD, 1264.54' TVD
Start Dir 2º/100' : 3006.93' MD, 2762.12'TVD
End Dir : 3930.91' MD, 3630.73' TVD
Total Depth : 7450.65' MD, 7097' TVD
BRU_ST_A1_COAL
STERLING_B
STERLING_C
BELUGA_D
BELUGA_E
BELUGA_F
BELUGA_G
BELUGA_H
BELUGA_I
BRU_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: BRU 241-23
78.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2633474.26 323392.31 61° 12' 15.3825 N 151° 0' 5.0347 W
SURVEY PROGRAM
Date: 2023-06-30T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 3058.00 BRU 241-23 wp07 (BRU 241-23) 3_MWD+AX+Sag
3058.00 7450.65 BRU 241-23 wp07 (BRU 241-23) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3282.60 3186.00 3572.53 BRU_ST_A1_COAL
3459.60 3363.00 3756.09 STERLING_B
3608.60 3512.00 3908.42 STERLING_C
3830.60 3734.00 4133.86 BELUGA_D
4035.60 3939.00 4342.03 BELUGA_E
4373.60 4277.00 4685.24 BELUGA_F
4815.60 4719.00 5134.06 BELUGA_G
5138.60 5042.00 5462.04 BELUGA_H
5848.60 5752.00 6183.00 BELUGA_I
6437.60 6341.00 6781.08 BRU_BELUGA_J
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 241-23, True North
Vertical (TVD) Reference:As-Built RKB @ 96.60usft
Measured Depth Reference:As-Built RKB @ 96.60usft
Calculation Method:Minimum Curvature
Project:Beluga River
Site:BRU K-Pad
Well:BRU 241-23
Wellbore:BRU 241-23
Design:BRU 241-23 wp07
CASING DETAILS
TVD TVDSS MD Size Name
120.00 23.40 120.00 16 16" Casing
2807.23 2710.63 3058.00 7-5/8 7 5/8" x 9 7/8"
7097.00 7000.40 7450.65 4-1/2 4 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
2 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD
3 550.00 6.00 346.00 549.63 10.15 -2.53 3.00 346.00 10.30
4 1303.24 28.48 335.62 1264.54 214.56 -87.27 3.00 -12.91 231.51 End Dir : 1303.24' MD, 1264.54' TVD
5 3006.93 28.48 335.62 2762.12 954.44 -422.52 0.00 0.00 1043.78 Start Dir 2º/100' : 3006.93' MD, 2762.12'TVD
6 3567.91 17.26 334.80 3278.19 1152.19 -513.44 2.00 -178.74 1261.41 BRU 241-23 wp07 tgt1
7 3930.91 10.00 334.80 3630.73 1229.53 -549.84 2.00 180.00 1346.87 End Dir : 3930.91' MD, 3630.73' TVD
8 7450.65 10.00 334.80 7097.00 1782.56 -810.07 0.00 0.00 1957.94 Total Depth : 7450.65' MD, 7097' TVD
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-1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0 100 200 300
West(-)/East(+) (200 usft/in)
BRU 241-23 wp07 tgt1
16" Casing
7 5/8" x 9 7/8"
4 1/2" x 6 3/4"
250500
7 5 0
1 0 0 0
1 2 5 0
1 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 0
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5 2 5 0
5 5 0 0
5 7 5 0
6 0 0 0
6 2 5 0
6 5 0 0
6 7 5 0
7 0 0 07097
B R U 2 4 1 -2 3 w p 0 7
Start Dir 3º/100' : 350' MD, 350'TVD
End Dir : 1303.24' MD, 1264.54' TVD
Start Dir 2º/100' : 3006.93' MD, 2762.12'TVD
End Dir : 3930.91' MD, 3630.73' TVD
Total Depth : 7450.65' MD, 7097' TVD CASING DETAILS
TVD TVDSS MD Size Name
120.00 23.40 120.00 16 16" Casing
2807.23 2710.63 3058.00 7-5/8 7 5/8" x 9 7/8"
7097.00 7000.40 7450.65 4-1/2 4 1/2" x 6 3/4"
Project: Beluga River
Site: BRU K-Pad
Well: BRU 241-23
Wellbore: BRU 241-23
Plan: BRU 241-23 wp07
WELL DETAILS: BRU 241-23
78.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2633474.26 323392.31 61° 12' 15.3825 N 151° 0' 5.0347 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 241-23, True North
Vertical (TVD) Reference:As-Built RKB @ 96.60usft
Measured Depth Reference:As-Built RKB @ 96.60usft
Calculation Method:Minimum Curvature
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-061
X
BRU 241-23
STRLG-BELUGA GASBELUGA RIVER
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