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HomeMy WebLinkAbout223-069Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/21/2026
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20260121
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 16RD 50133205540100 207125 12/3/2025 AK E-LINE PPROF
T41253
BRU 211-35 50283201890000 223050 11/7/2025 AK E-LINE Perf
T41254
BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf
T41255
BRU 213-26T 50283202040000 225038 11/4/2025 AK E-LINE Perf
T41256
BRU 241-34S 50283201980000 224077 11/9/2025 AK E-LINE Perf
T41257
BRU 241-34T 50283201810000 220052 11/6/2025 AK E-LINE Perf
T41258
BRU 244-27 50283201850000 222038 12/13/2025 AK E-LINE Perf
T41259
BRU 244-27 50283201850000 222038 12/19/2025 AK E-LINE StripGun
T41259
GP ST 17586 9 50733204480000 193062 11/13/2025 AK E-LINE Perf
T41260
IRU 241-01 50283201840000 221076 12/21/2025 AK E-LINE Perf
T41261
IRU 241-01 50283201840000 221076 12/30/2025 AK E-LINE Perf
T41261
IRU 241-01 50283201840000 221076 12/16/2025 AK E-LINE Plug
T41261
IRU 241-01 50283201840000 221076 11/26/2025 AK E-LINE Plug/Perf
T41261
KALOTSA 01 50133206570000 216132 11/19/2025 AK E-LINE Perf
T41262
KBU 31-18 50133206490000 215024 11/8/2025 AK E-LINE Drift/PPROF
T41263
KU 12-17 50133205770000 208089 11/14/2025 AK E-LINE StimGun
T41264
LRU C-01RD 50283200610100 201168 11/27/2025 AK E-LINE RCT/Perf
T41265
MPI 2-32 50029220840000 190119 12/10/2025 AK E-LINE LDL
T41266
MPI 2-38 50029220900000 190129 12/5/2025 AK E-LINE LDL
T41267
MPU H-16 50029232270000 204190 12/3/2025 AK E-LINE CBL
T41268
MPU H-16 50029232270000 204190 11/19/2025 AK E-LINE TubingCut
T41268
MPU I-14 50029232140000 204119 11/13/2025 AK E-LINE CBL
T41269
NCIU A-06A 50883200260100 225071 11/28/2025 AK E-LINE Perf/Plug
T41270
NCIU A-08 50883200280000 169063 12/2/2025 AK E-LINE GPT
T41271
NCIU A-19 50883201940000 224026 12/16/2025 AK E-LINE GPT
T41272
NCIU A-19 50883201940000 224026 12/12/2025 AK E-LINE GPT/Perf/Plug
T41272
NCIU A-19 50883201940000 224026 12/17/2025 AK E-LINE Perf
T41272
NCIU A-21A 50883201990100 225075 12/30/2025 AK E-LINE PPROF
T41273
OP19-T1N 50029234910000 213068 11/19/2025 AK E-LINE TubingPunch
T41274
BRU 213-26 50283201920000 223069 11/23/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.01.21 13:56:35 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
PCU D-10 50283202080000 225082 12/9/2025 AK E-LINE Perf T41275
SCU 322C-04 50133101040100 215217 12/4/2025 AK E-LINE TubingPunch T41276
SRU 222-33 50133207150000 223100 12/7/2025 AK E-LINE Plug T41277
SU 43-10 50133207390000 225107 11/26/2025 AK E-LINE CBL T41278
TBU A-12RD 50733200760100 171029 11/29/2025 AK E-LINE Perf T41279
TBU D-24A 50733202240100 174064 12/2/2025 AK E-LINE TubingPunch T41280
TBU D-24A 50733202240100 174064 11/21/2025 AK E-LINE TubingPunch T41280
TBU M-10 50733205880000 209154 11/15/2025 AK E-LINE Perf T41281
Please include current contact information if different from above.
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.01.21 13:56:51 -09'00'
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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other:
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,200' N/A
Casing Collapse
Structural
Conductor
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
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:
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
chelgeson@hilcorp.com
Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA029657
223-069
50-283-20192-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6 # / L-80
TVD Burst
2,705'
8,430psi
2,530'
Tubing Size:
Size
2,888'
MD
See Attached Schematic
120'
2,888'
120'
6,890psi
120'
November 20, 2025
Tieback 4-1/2"
7,196'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 213-26CO 802A
Same
6,679'4-1/2"
~1660psi
4,503'
6,164'
Length
Baker ZXP LTP; N/A 2,693' MD / 2,351' TVD; N/A
6,683' 6,129' 5,646'
Beluga River Sterling-Beluga Gas Pool
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 8:50 am, Nov 12, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.11.10 17:59:24 -
09'00'
Noel Nocas
(4361)
325-688
10-404
BJM 11/17/25 DSR-11/13/25TS 11/17/25
11/17/25
Well Prognosis
Well Name: BRU 213-26 API Number: 50-283-20192-00-00
Current Status: Gas Producer Permit to Drill Number: 223-069
First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C)
Second Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8663 (C)
Maximum Expected BHP: 1785 psi @ 4152 TVD (Based on 0.43 psi/ft gradient))
Max. Potential Surface Pressure: 1660 psi (Based on 0.03 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.671 psi/ft using 12.9 ppg EMW FIT at the Surface shoe (2888ft)
Shallowest Allowable Perf TVD: MPSP/(0.671-0.03) = 1660 psi / 0.641 = 2,589 TVD
Top of SBGP (CO 802A): ~3,157 MD/ ~2,782 TVD
Brief Well Summary
Drilled & completed in 2023, BRU 213-26 is an online producer in the Beluga River Unit (BRU) Sterling-Beluga Gas
Pool (SBGP) with a 4-1/2 completion. The D sands have been tested in nearby wells and determined low risk
perf adds.
Objective:
The purpose of this work/sundry is to increase production by adding additional perforations in the Beluga D
sands. All sands lie in the BRU SBGP and PA.
Wellbore Conditions:
Flowing at ~3500mcf @ 300 psi with 8 bwpd
4-1/2 TOC @ ~2700 from CBL 10-19-23
Procedure
1. RU E-line, PT lubricator to 250/2000 psi
2. Perforate Beluga sands within the below intervals:
3. Return well to production
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
Formation MD TOP MD BASE TVD TOP TVD BASE H
Top Pool/PA ~3,157 ~2,782'
BEL D1 ±3,999' ±4,002' ±3,588' ±3,590' ±3'
BEL D1 ±4,006' ±4,024' ±3,594' ±3,611' ±18'
BEL D2 ±4,033' ±4,037' ±3,620' ±3,624' ±4'
BEL D3 ±4,047' ±4,053' ±3,633' ±3,639' ±6'
BEL D4 ±4,088' ±4,095' ±3,673' ±3,679' ±7'
BEL D5 ±4,114' ±4,119' ±3,697' ±3,702' ±5'
BEL D5 ±4,123' ±4,127' ±3,706' ±3,710' ±4'
BEL D6 ±4,157' ±4,178' ±3,739' ±3,759' ±21'
Shallowest allowable perf should be calculated based on last known pressure of deepest uncemented perf
unless evidence of depletion is submitted for the record. Shallowest allowable perf = 3310' TVD based on open
perfs at 5433' TVD @ .45 psi/ft reservoir gradient. The proposed perfs in this sundry are deeper. -bjm
Updated by DMA 07-10-25
SCHEMATIC
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112 MD / 6,597 TVD
TD = 7,200 MD / 6,683 TVD
RKB to GL = 19.8
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-BTC 6.875 Surf 2,888
4-1/2" Prod Lnr 12.6 L-80 TXP-BTC 3.958 2,693 7,196
4-1/2" Prod Tieback 12.6 L-80 TXP-BTC 3.958 Surf 2,705
4
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 19.8 11 Cactus CTF-ONE-CTL Hanger w/ 4 Type H BPV
2 1,529 3.958 4.500 Chemical Injection Mandrel
3 2,693 4.875 6.540 Seal Stem 1.8 off seat / 5-1/2 Liner hanger w/ ZXP-
RS-Flex LTP
4 6,164 - - CIBP w/ 35 of cement on top (11/9/23)
6-3/4
hole
3
2
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool (CO 802A): 3157 MD to 2782 TVD
Beluga E 4,204 4,217 3,784 3,796 13 7/7/2025 Open
Beluga E1 4,235 4,248 3,814 3,826 13 7/7/2025 Open
Beluga E1 4,279 4,283 3,856 3,860 4 7/7/2025 Open
Beluga E2 4,306 4,309 3,883 3,886 3 7/7/2025 Open
Beluga E3 4,337 4,340 3,913 3,916 3 7/7/2025 Open
Beluga E3 4,354 4,368 3,929 3,943 14 7/7/2025 Open
Beluga E3 4,390 4,395 3,964 3,969 5 7/7/2025 Open
Beluga E5 4,438 4,441 4,011 4,014 3 7/7/2025 Open
Beluga E5 4,474 4,477 4,046 4,049 3 6/23/2025 Open
Beluga E6 4,513 4,525 4,084 4,096 12 6/23/2025 Open
Beluga E6 4,528 4,545 4,099 4,115 17 6/23/2025 Open
Beluga F4 4,711 4,723 4,277 4,288 12 11/13/2023 Open
Beluga F5 4,731 4,736 4,296 4,301 5 11/13/2023 Open
Beluga F6 4,776 4,790 4,340 4,353 14 11/13/2023 Open
Beluga F6 4,831 4,839 4,393 4,400 8 11/13/2023 Open
Beluga F6 4,860 4,866 4,421 4,426 6 11/13/2023 Open
Beluga F7 4,983 4,987 4,539 4,542 4 11/13/2023 Open
Beluga F7 4,999 5,003 4,554 4,558 4 11/13/2023 Open
Beluga F7 5,011 5,016 4,566 4,570 5 11/13/2023 Open
Beluga F10 5,062 5,065 4,615 4,617 3 11/13/2023 Open
Beluga F10 5,084 5,087 4,636 4,639 3 11/13/2023 Open
Beluga F10 5,111 5,113 4,662 4,664 2 11/12/2023 Open
Continued on following page
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2 Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700 MD (CBL date 10-19-23).
1
Updated by DMA 07-10-25
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
SCHEMATIC
PERFORATION DETAIL (Continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Beluga G1 5,150 5,155 4,700 4,704 5 11/12/2023 Open
Beluga G2 5,165 5,168 4,714 4,717 3 11/12/2023 Open
Beluga G3 5,204 5,209 4,752 4,757 5 11/12/2023 Open
Beluga G4 5,264 5,267 4,810 4,812 3 11/12/2023 Open
Beluga G6 5,316 5,339 4,860 4,882 23 11/11/2023 Open
Beluga H 5,513 5,519 5,050 5,056 6 11/11/2023 Open
Beluga H 5,524 5,534 5,060 5,070 10 11/11/2023 Open
Beluga H2 5,612 5,620 5,146 5,153 8 11/11/2023 Open
Beluga H3 5,656 5,660 5,188 5,182 4 11/10/2023 Open
Beluga H6 5,783 5,789 5,311 5,317 6 11/10/2023 Open
Beluga H7 5,803 5,813 5,330 5,340 10 11/10/2023 Open
Beluga H7 5,819 5,827 5,346 5,353 8 11/10/2023 Open
Beluga H7 5,830 5,845 5,356 4,371 15 11/10/2023 Open
Beluga H9 5,880 5,883 5,405 5,407 3 11/10/2023 Open
Beluga H10 5,909 5,918 5,433 5,441 9 11/10/2023 Open
Beluga H15 6,214 6,224 5,727 5,737 10 11/5/2023 Isolated
Beluga I4 6,502 6,512 6,005 6,014 10 11/5/2023 Isolated
Beluga I11 6,763 6,772 6,258 6,266 9 11/5/2023 Isolated
Updated by DMA 08-28-25
PROPOSED
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112 MD / 6,597 TVD
TD = 7,200 MD / 6,683 TVD
RKB to GL = 19.8
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-BTC 6.875 Surf 2,888
4-1/2" Prod Lnr 12.6 L-80 TXP-BTC 3.958 2,693 7,196
4-1/2" Prod Tieback 12.6 L-80 TXP-BTC 3.958 Surf 2,705
4
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 19.8 11 Cactus CTF-ONE-CTL Hanger w/ 4 Type H BPV
2 1,529 3.958 4.500 Chemical Injection Mandrel
3 2,693 4.875 6.540 Seal Stem 1.8 off seat / 5-1/2 Liner hanger w/ ZXP-
RS-Flex LTP
4 6,164 - - CIBP w/ 35 of cement on top (11/9/23)
6-3/4
hole
3
2
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool (CO 802A): 3157 MD to 2782 TVD
BEL D1 ±3,999' ±4,002' ±3,588' ±3,590' ±3' Proposed TBD
BEL D1 ±4,006' ±4,024' ±3,594' ±3,611' ±18' Proposed TBD
BEL D2 ±4,033' ±4,037' ±3,620' ±3,624' ±4' Proposed TBD
BEL D3 ±4,047' ±4,053' ±3,633' ±3,639' ±6' Proposed TBD
BEL D4 ±4,088' ±4,095' ±3,673' ±3,679' ±7' Proposed TBD
BEL D5 ±4,114' ±4,119' ±3,697' ±3,702' ±5' Proposed TBD
BEL D5 ±4,123' ±4,127' ±3,706' ±3,710' ±4' Proposed TBD
BEL D6 ±4,157' ±4,178' ±3,739' ±3,759' ±21' Proposed TBD
BEL E 4,204' 4,217' 3,784' 3,796' 13' 7/7/2025 Open
BEL E1 4,235' 4,248' 3,814' 3,826' 13' 7/7/2025 Open
BEL E1 4,279' 4,283' 3,856' 3,860' 4' 7/7/2025 Open
BEL E2 4,306' 4,309' 3,883' 3,886' 3' 7/7/2025 Open
BEL E3 4,337' 4,340' 3,913' 3,916' 3' 7/7/2025 Open
BEL E3 4,354' 4,368' 3,929' 3,943' 14' 7/7/2025 Open
BEL E3 4,390' 4,395' 3,964' 3,969' 5' 7/7/2025 Open
BEL E5 4,438' 4,441' 4,011' 4,014' 3' 7/7/2025 Open
BEL E5 4,474' 4,477' 4,046' 4,049' 3' 6/23/2025 Open
BEL E6 4,513' 4,525' 4,084' 4,096' 12' 6/23/2025 Open
BEL E6 4,528' 4,545' 4,099' 4,115' 17' 6/23/2025 Open
BEL F4 4,711' 4,723' 4,277' 4,288' 12' 11/13/2023 Open
BEL F5 4,731' 4,736' 4,296' 4,301' 5' 11/13/2023 Open
BEL F6 4,776' 4,790' 4,340' 4,353' 14' 11/13/2023 Open
BEL F6 4,831' 4,839' 4,393' 4,400' 8' 11/13/2023 Open
BEL F6 4,860' 4,866' 4,421' 4,426' 6' 11/13/2023 Open
BEL F7 4,983' 4,987' 4,539' 4,542' 4' 11/13/2023 Open
BEL F7 4,999' 5,003' 4,554' 4,558' 4' 11/13/2023 Open
BEL F7 5,011' 5,016' 4,566' 4,570' 5' 11/13/2023 Open
BEL F10 5,062' 5,065' 4,615' 4,617' 3' 11/13/2023 Open
BEL F10 5,084' 5,087' 4,636' 4,639' 3' 11/13/2023 Open
BEL F10 5,111' 5,113' 4,662' 4,664' 2' 11/12/2023 Open
Continued on following page
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2 Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700 MD (CBL date 10-19-23).
1
Updated by DMA 08-28-25
PROPOSED
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PERFORATION DETAIL (Continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL G1 5,150' 5,155' 4,700' 4,704' 5' 11/12/2023 Open
BEL G2 5,165' 5,168' 4,714' 4,717' 3' 11/12/2023 Open
BEL G3 5,204' 5,209' 4,752' 4,757' 5' 11/12/2023 Open
BEL G4 5,264' 5,267' 4,810' 4,812' 3' 11/12/2023 Open
BEL G6 5,316' 5,339' 4,860' 4,882' 23' 11/11/2023 Open
BEL H 5,513' 5,519' 5,050' 5,056' 6' 11/11/2023 Open
BEL H 5,524' 5,534' 5,060' 5,070' 10' 11/11/2023 Open
BEL H2 5,612' 5,620' 5,146' 5,153' 8' 11/11/2023 Open
BEL H3 5,656' 5,660' 5,188' 5,182' 4' 11/10/2023 Open
BEL H6 5,783' 5,789' 5,311' 5,317' 6' 11/10/2023 Open
BEL H7 5,803' 5,813' 5,330' 5,340' 10' 11/10/2023 Open
BEL H7 5,819' 5,827' 5,346' 5,353' 8' 11/10/2023 Open
BEL H7 5,830' 5,845' 5,356' 4,371' 15' 11/10/2023 Open
BEL H9 5,880' 5,883' 5,405' 5,407' 3' 11/10/2023 Open
BEL H10 5,909' 5,918' 5,433' 5,441' 9' 11/10/2023 Open
BEL H15 6,214' 6,224' 5,727' 5,737' 10' 11/5/2023 Isolated
BEL I4 6,502' 6,512' 6,005' 6,014' 10' 11/5/2023 Isolated
BEL I11 6,763' 6,772' 6,258' 6,266' 9' 11/5/2023 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: 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.
T40744BRU 213-26 50283201920000 223069 7/7/2025 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 213-26 50283201920000 223069 6/23/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.07.16 10:52:24 -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: ______________________
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 7,200 feet 6,164 feet
true vertical 6,683 feet N/A feet
Effective Depth measured 5,646 feet 2,693 feet
true vertical feet 2,351 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 2,705' MD 2,362' TVD
Packers and SSSV (type, measured and true vertical depth) Baker ZXP LTP; N/A 2,593' MD 2,351' 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:
Chad Helgeson, Operations Engineer
325-118
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
3558
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
chelgeson@hilcorp.com
907-777-8405
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'
4 04933
0 29112
331
4-1/2"
Intermediate
16"
7-5/8"
120'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-069
50-283-20192-00-00
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:
FEDA029657
Beluga River / Sterling-Beluga Gas
Beluga River Unit (BRU) 213-26
measured
true vertical
Production
Liner
4,503'
Casing
Structural
6,679'7,196'
120'Conductor
Surface 2,888'
TVD
*Beluga River, Strlg-Beluga Gas Pool, Prod Code 92500
7,500psi
6,890psi
8,430psi
2888` 2,530'
Burst Collapse
4,790psi
measured
Packer
Plugs
Junk measured
Length
p
k
ft
t
Fra
O
s O
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 3:07 pm, Jul 14, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.07.14 14:57:08 -
08'00'
Noel Nocas
(4361)
BJM 9/25/25
Page 1/1
Well Name: BRU 213-26
Report Printed: 7/9/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-283-20192-00-00 Field Name:Beluga River State/Province:ALASKA
Permit to Drill (PTD) #:223-069 Sundry #:325-118 Rig Name/No:
Jobs
Actual Start Date:2/13/2025 End Date:
Report Number
1
Report Start Date
6/23/2025
Report End Date
6/24/2025
Last 24hr Summary
PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string (1 x CCL, 2 x wt bars, 1 x spangs, 1 x gr 2.33"), Pressure test 250/2500-good, Run in the
hole to 4610', Pull out of hole, Pick up & make up run #2 (2.5" x 6' gun), Run in the hole, Perf BEL E6 4534-4540, Pull out of hole, Pick up & make up run #3 (17' x
2" gun), Run in the hole, Perf BEL E6 4528-4545, Pull out of the hole, Pick up & make up run #4 (2" x 12' gun), Run in the hole, Correlate, Perf BEL E6 4513-4525,
Pull out of the hole, Pick up & make up run #5 (2" x 3'), Run in the hole, Correlate, Perf BEL E5 4474-4477, Pull out of the hole. Rig down & secure well for the
night.
Report Number
2
Report Start Date
7/7/2025
Report End Date
7/8/2025
Last 24hr Summary
PTW / PJSM. PT PCE to 250 psi low / 2000 psi high. Pinched well back to 350 psi tubing pressure, rate dropped from 3.2 mm to 0.5 mm. Logged GR CCL pass
across BEL E-sands. Shifted as per Geo. Made eight 2.5" gun runs on CCL and perforated the following intervals w/correlation passes verified by OE / Res / Geo:
E5 4438 - 4441, E3 4390 - 4395, E3 4354 - 4368, E3 4337 - 4340, E2 4306 - 4309, E1 4279 - 4283, E1 4235 - 4248, E 4204- 4217. Install tree cap. SDFN.
Turn over to ops.
2" gun), Run in the hole, Perf BEL E6 4528-4545, Pull out of the hole, Pick up & make up run #4 (2" x 12' gun), Run in the hole
Pull out of the hole, Pick up & make up run #5 (2" x 3'), Run in the hole, Correlate, Perf BEL E5 4474-4477, Pull out of the ho
hole to 4610', Pull out of hole, Pick up & make up run #2 (2.5" x 6' gun), Run in the hole, Perf BEL E6 4534-4540, Pull out of
2" gun), Run in the hole, Perf BEL E6 4528-4545, Pull out of the hole, Pick up & make up run #4 (2" x 12' gun), Run in the hole
hole, Pick up & make up run #3 (17' x
, Correlate, Perf BEL E6 4513-4525,
across BEL E-sands. Shifted as per Geo. Made eight 2.5" gun runs on CCL and perforated the following intervals w/correlation passes verified by OE / Res / Geo:
E5 4438 - 4441, E3 4390 - 4395, E3 4354 - 4368, E3 4337 - 4340, E2 4306 - 4309, E1 4279 - 4283, E1 4235 - 4248, E 4204- 4217. Install tree cap. SDFN.
PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string (1 x CCL, 2 x wt bars, 1 x spangs, 1 x gr 2.33"), P
hole to 4610', Pull out of hole, Pick up & make up run #2 (2.5" x 6' gun), Run in the hole, Perf BEL E6 4534-4540, Pull out of
Updated by DMA 07-10-25
SCHEMATIC
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112 MD / 6,597 TVD
TD = 7,200 MD / 6,683 TVD
RKB to GL = 19.8
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-BTC 6.875 Surf 2,888
4-1/2" Prod Lnr 12.6 L-80 TXP-BTC 3.958 2,693 7,196
4-1/2" Prod Tieback 12.6 L-80 TXP-BTC 3.958 Surf 2,705
4
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 19.8 11 Cactus CTF-ONE-CTL Hanger w/ 4 Type H BPV
2 1,529 3.958 4.500 Chemical Injection Mandrel
3 2,693 4.875 6.540 Seal Stem 1.8 off seat / 5-1/2 Liner hanger w/ ZXP-
RS-Flex LTP
4 6,164 - - CIBP w/ 35 of cement on top (11/9/23)
6-3/4
hole
3
2
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool (CO 802A): 3157 MD to 2782 TVD
Beluga E 4,204 4,217 3,784 3,796 13 7/7/2025 Open
Beluga E1 4,235 4,248 3,814 3,826 13 7/7/2025 Open
Beluga E1 4,279 4,283 3,856 3,860 4 7/7/2025 Open
Beluga E2 4,306 4,309 3,883 3,886 3 7/7/2025 Open
Beluga E3 4,337 4,340 3,913 3,916 3 7/7/2025 Open
Beluga E3 4,354 4,368 3,929 3,943 14 7/7/2025 Open
Beluga E3 4,390 4,395 3,964 3,969 5 7/7/2025 Open
Beluga E5 4,438 4,441 4,011 4,014 3 7/7/2025 Open
Beluga E5 4,474 4,477 4,046 4,049 3 6/23/2025 Open
Beluga E6 4,513 4,525 4,084 4,096 12 6/23/2025 Open
Beluga E6 4,528 4,545 4,099 4,115 17 6/23/2025 Open
Beluga F4 4,711 4,723 4,277 4,288 12 11/13/2023 Open
Beluga F5 4,731 4,736 4,296 4,301 5 11/13/2023 Open
Beluga F6 4,776 4,790 4,340 4,353 14 11/13/2023 Open
Beluga F6 4,831 4,839 4,393 4,400 8 11/13/2023 Open
Beluga F6 4,860 4,866 4,421 4,426 6 11/13/2023 Open
Beluga F7 4,983 4,987 4,539 4,542 4 11/13/2023 Open
Beluga F7 4,999 5,003 4,554 4,558 4 11/13/2023 Open
Beluga F7 5,011 5,016 4,566 4,570 5 11/13/2023 Open
Beluga F10 5,062 5,065 4,615 4,617 3 11/13/2023 Open
Beluga F10 5,084 5,087 4,636 4,639 3 11/13/2023 Open
Beluga F10 5,111 5,113 4,662 4,664 2 11/12/2023 Open
Continued on following page
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2 Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700 MD (CBL date 10-19-23).
1
Updated by DMA 07-10-25
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
SCHEMATIC
PERFORATION DETAIL (Continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Beluga G1 5,150 5,155 4,700 4,704 5 11/12/2023 Open
Beluga G2 5,165 5,168 4,714 4,717 3 11/12/2023 Open
Beluga G3 5,204 5,209 4,752 4,757 5 11/12/2023 Open
Beluga G4 5,264 5,267 4,810 4,812 3 11/12/2023 Open
Beluga G6 5,316 5,339 4,860 4,882 23 11/11/2023 Open
Beluga H 5,513 5,519 5,050 5,056 6 11/11/2023 Open
Beluga H 5,524 5,534 5,060 5,070 10 11/11/2023 Open
Beluga H2 5,612 5,620 5,146 5,153 8 11/11/2023 Open
Beluga H3 5,656 5,660 5,188 5,182 4 11/10/2023 Open
Beluga H6 5,783 5,789 5,311 5,317 6 11/10/2023 Open
Beluga H7 5,803 5,813 5,330 5,340 10 11/10/2023 Open
Beluga H7 5,819 5,827 5,346 5,353 8 11/10/2023 Open
Beluga H7 5,830 5,845 5,356 4,371 15 11/10/2023 Open
Beluga H9 5,880 5,883 5,405 5,407 3 11/10/2023 Open
Beluga H10 5,909 5,918 5,433 5,441 9 11/10/2023 Open
Beluga H15 6,214 6,224 5,727 5,737 10 11/5/2023 Isolated
Beluga I4 6,502 6,512 6,005 6,014 10 11/5/2023 Isolated
Beluga I11 6,763 6,772 6,258 6,266 9 11/5/2023 Isolated
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.PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,200'N/A
Casing Collapse
Structural
Conductor
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
Baker ZXP LTP; N/A 2,693' MD / 2,351' TVD; N/A
6,683'6,129'5,646'
Beluga River Sterling-Beluga Gas Pool
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 213-26CO 802A
Same
6,679'4-12/"
~1660
4,503'
6,164'
Length
March 17, 2025
Tieback 4-1/2"
7,196'
Perforation Depth MD (ft):
6,890psi
120'
2,888'
MD
See Attached Schematic
120'
2,888'
120'
12.6 # / L-80
TVD Burst
2,705'
8,430psi
2,530'
Tubing Size:
Size
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA029657
223-069
50-283-20192-00-00
Hilcorp Alaska, LLC
Proposed Pools:
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):
chelgeson@hilcorp.com
Perforation Depth TVD (ft):
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:
Chad Helgeson, Operations Engineer
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
325-118
By Gavin Gluyas at 8:12 am, Mar 03, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.02.28 10:45:34 -
09'00'
Noel Nocas
(4361)
A.Dewhurst 05MAR25BJM 3/18/25
10-404
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.03.19 10:20:42 -08'00'03/19/25
RBDMS JSB 071825
Well Prognosis
Well Name: BRU 213-26 API Number: 50-283-20192-00-00
Current Status: Gas Producer Permit to Drill Number: 223-069
First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C)
Second Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8663 (C)
Maximum Expected BHP: 1785 psi @ 4152’ TVD (Based on 0.43 psi/ft gradient))
Max. Potential Surface Pressure: 1660 psi (Based on 0.03 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.671 psi/ft using 12.9 ppg EMW FIT at the Surface shoe (2888ft)
Shallowest Allowable Perf TVD: MPSP/(0.671-0.03) = 1660 psi / 0.641 = 2,589‘ TVD
Top of SBGP (CO 802A): ~3,157’ MD/ ~2,782’ TVD
Brief Well Summary
Drilled & completed in 2023, BRU 213-26 is an online producer in the Beluga River Unit (BRU) Sterling-Beluga Gas
Pool (SBGP) with a 4-1/2” completion. The E sands have been tested in nearby wells and determined low risk
perf adds.
Objective:
The purpose of this work/sundry is to increase production by adding additional perforations in the Beluga E
sands. All sands lie in the BRU SBGP.
Wellbore Conditions:
x Flowing at ~2900mcf @ 300 psi with 8 bwpd
x 4-1/2” TOC @ ~2700’ from CBL 10-19-23
Procedure
1. RU E-line, PT lubricator to 250/2000 psi
2. Perforate Beluga sands within the below intervals with the well shut-in:
3. Return well to production
Formation MD TOP MD BASE TVD TOP TVD BASE H
Top Pool ~3,157’
~2,782'
Beluga E ±4,204 ±4,217 ±3,784 ±3,796 ±13
Beluga E1 ±4,235 ±4,248 ±3,814 ±3,826 ±13
Beluga E1 ±4,279 ±4,283 ±3,856 ±3,860 ±4
Beluga E2 ±4,306 ±4,309 ±3,883 ±3,886 ±3
Beluga E3 ±4,337 ±4,340 ±3,913 ±3,916 ±3
Beluga E3 ±4,354 ±4,369 ±3,929 ±3,944 ±15
Beluga E3 ±4,390 ±4,395 ±3,964 ±3,969 ±5
Beluga E5 ±4,438 ±4,441 ±4,011 ±4,014 ±3
Beluga E5 ±4,474 ±4,477 ±4,046 ±4,049 ±3
Beluga E6 ±4,513 ±4,525 ±4,084 ±4,096 ±12
Beluga E6 ±4,528 ±4,545 ±4,099 ±4,115 ±17
Beluga E6 ±4,560 ±4,565 ±4,130 ±4,135 ±5
Beluga E6 ±4,576 ±4,583 ±4,145 ±4,152 ±7
Well Prognosis
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
Updated by CAH 02-27-25
SCHEMATIC
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112’ MD / 6,597’ TVD
TD = 7,200’ MD / 6,683’ TVD
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 2,888’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,693’ 7,196’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,705’
3
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,529’ 3.958” 4.500” Chemical Injection Sub
2 2,693’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 6,164’ - - CIBP w/ 35’ of cement on top (11/9/23)
6-3/4”
hole
2
1
PERFORATION DETAIL
Sands Top
MD
Btm
MD Top TVD Btm TVD FT Date Status
Beluga F4 4711 4723 4277 4288 12 11/13/2023 Open
Beluga F5 4731 4736 4296 4301 5 11/13/2023 Open
Beluga F6 4776 4790 4340 4353 14 11/13/2023 Open
Beluga F6 4831 4839 4393 4400 8 11/13/2023 Open
Beluga F6 4860 4866 4421 4426 6 11/13/2023 Open
Beluga F7 4983 4987 4539 4542 4 11/13/2023 Open
Beluga F7 4999 5003 4554 4558 4 11/13/2023 Open
Beluga F7 5011 5016 4566 4570 5 11/13/2023 Open
Beluga F10 5062 5065 4615 4617 3 11/13/2023 Open
Beluga F10 5084 5087 4636 4639 3 11/13/2023 Open
Beluga F10 5111 5113 4662 4664 2 11/12/2023 Open
Beluga G1 5150 5155 4700 4704 5 11/12/2023 Open
Beluga G2 5165 5168 4714 4717 3 11/12/2023 Open
Beluga G3 5204 5209 4752 4757 5 11/12/2023 Open
Beluga G4 5264 5267 4810 4812 3 11/12/2023 Open
Beluga G6 5316 5339 4860 4882 23 11/11/2023 Open
Beluga H 5513 5519 5050 5056 6 11/11/2023 Open
Beluga H 5524 5534 5060 5070 10 11/11/2023 Open
Beluga H2 5612 5620 5146 5153 8 11/11/2023 Open
Beluga H3 5656 5660 5188 5182 4 11/10/2023 Open
Beluga H6 5783 5789 5311 5317 6 11/10/2023 Open
Beluga H7 5803 5813 5330 5340 10 11/10/2023 Open
Beluga H7 5819 5827 5346 5353 8 11/10/2023 Open
Beluga H7 5830 5845 5356 4371 15 11/10/2023 Open
Beluga H9 5880 5883 5405 5407 3 11/10/2023 Open
Beluga H10 5909 5918 5433 5441 9 11/10/2023 Open
Beluga H15 6214 6224 5727 5737 10 11/5/2023 Isolated
Beluga I4 6502 6512 6005 6014 10 11/5/2023 Isolated
Beluga I11 6763 6772 6258 6266 9 11/5/2023 Isolated
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2” Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700’ MD.
Updated by CAH 02-27-25
PROPOSED
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112’ MD / 6,597’ TVD
TD = 7,200’ MD / 6,683’ TVD
RKB to GL = 19.8’
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-BTC 6.875” Surf 2,888’
4-1/2" Prod Lnr 12.6 L-80 TXP-BTC 3.958” 2,693’ 7,196’
4-1/2" Prod Tieback 12.6 L-80 TXP-BTC 3.958” Surf 2,705’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 19.8’ 11” Cactus CTF-ONE-CTL Hanger w/ 4” Type H BPV
2 1,529’ 3.958” 4.500” Chemical Injection Mandrel
3 2,693’ 4.875” 6.540” Seal Stem 1.8’ off seat / 5-1/2” Liner hanger w/ ZXP-
RS-Flex LTP
4 6,164’ - - CIBP w/ 35’ of cement on top (11/9/23)
6-3/4”
hole
3
2
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool (CO 802A): 3157’ MD to 2782’ TVD
Beluga E ±4,204 ±4,217 ±3,784 ±3,796 ±13 TBD Proposed
Beluga E1 ±4,235 ±4,248 ±3,814 ±3,826 ±13 TBD Proposed
Beluga E1 ±4,279 ±4,283 ±3,856 ±3,860 ±4 TBD Proposed
Beluga E2 ±4,306 ±4,309 ±3,883 ±3,886 ±3 TBD Proposed
Beluga E3 ±4,337 ±4,340 ±3,913 ±3,916 ±3 TBD Proposed
Beluga E3 ±4,354 ±4,369 ±3,929 ±3,944 ±15 TBD Proposed
Beluga E3 ±4,390 ±4,395 ±3,964 ±3,969 ±5 TBD Proposed
Beluga E5 ±4,438 ±4,441 ±4,011 ±4,014 ±3 TBD Proposed
Beluga E5 ±4,474 ±4,477 ±4,046 ±4,049 ±3 TBD Proposed
Beluga E6 ±4,513 ±4,525 ±4,084 ±4,096 ±12 TBD Proposed
Beluga E6 ±4,528 ±4,545 ±4,099 ±4,115 ±17 TBD Proposed
Beluga E6 ±4,560 ±4,565 ±4,130 ±4,135 ±5 TBD Proposed
Beluga E6 ±4,576 ±4,583 ±4,145 ±4,152 ±7 TBD Proposed
Beluga F4 4,711 4,723 4,277 4,288 12 11/13/2023 Open
Beluga F5 4,731 4,736 4,296 4,301 5 11/13/2023 Open
Beluga F6 4,776 4,790 4,340 4,353 14 11/13/2023 Open
Beluga F6 4,831 4,839 4,393 4,400 8 11/13/2023 Open
Beluga F6 4,860 4,866 4,421 4,426 6 11/13/2023 Open
Beluga F7 4,983 4,987 4,539 4,542 4 11/13/2023 Open
Beluga F7 4,999 5,003 4,554 4,558 4 11/13/2023 Open
Beluga F7 5,011 5,016 4,566 4,570 5 11/13/2023 Open
Beluga F10 5,062 5,065 4,615 4,617 3 11/13/2023 Open
Beluga F10 5,084 5,087 4,636 4,639 3 11/13/2023 Open
Beluga F10 5,111 5,113 4,662 4,664 2 11/12/2023 Open
Continued on following page
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2” Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700’ MD (CBL date 10-19-23).
1
Updated by CAH 02-27-25
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PROPOSED
PERFORATION DETAIL (Continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Beluga G1 5,150 5,155 4,700 4,704 5 11/12/2023 Open
Beluga G2 5,165 5,168 4,714 4,717 3 11/12/2023 Open
Beluga G3 5,204 5,209 4,752 4,757 5 11/12/2023 Open
Beluga G4 5,264 5,267 4,810 4,812 3 11/12/2023 Open
Beluga G6 5,316 5,339 4,860 4,882 23 11/11/2023 Open
Beluga H 5,513 5,519 5,050 5,056 6 11/11/2023 Open
Beluga H 5,524 5,534 5,060 5,070 10 11/11/2023 Open
Beluga H2 5,612 5,620 5,146 5,153 8 11/11/2023 Open
Beluga H3 5,656 5,660 5,188 5,182 4 11/10/2023 Open
Beluga H6 5,783 5,789 5,311 5,317 6 11/10/2023 Open
Beluga H7 5,803 5,813 5,330 5,340 10 11/10/2023 Open
Beluga H7 5,819 5,827 5,346 5,353 8 11/10/2023 Open
Beluga H7 5,830 5,845 5,356 4,371 15 11/10/2023 Open
Beluga H9 5,880 5,883 5,405 5,407 3 11/10/2023 Open
Beluga H10 5,909 5,918 5,433 5,441 9 11/10/2023 Open
Beluga H15 6,214 6,224 5,727 5,737 10 11/5/2023 Isolated
Beluga I4 6,502 6,512 6,005 6,014 10 11/5/2023 Isolated
Beluga I11 6,763 6,772 6,258 6,266 9 11/5/2023 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: 2/2/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240202
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 213-26 50283201920000 223069 11/5/2023 AK E-LINE PERF
KU 13-06A 50133207160000 223112 12/28/2023 AK E-LINE CBL
MPU B-09 50029212970000 185034 1/26/2024 READ Caliper Survey
MPU B-19 50029214510000 185230 1/26/2024 READ Caliper Survey
PBU W-08A 50029219060100 202090 12/27/2023 HALLIBURTON WFL-TMD3D
SRU 222-33 50133207150000 223100 12/16/2023 AK E-LINE CBL
Please include current contact information if different from above.
T38477
T38478
T38479
T38480
T38481
T38482
2/2/2024
BRU 213-26 50283201920000 223069 11/5/2023 AK E-LINE PERF
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.02.02
15:40:47 -09'00'
David Douglas Hilcorp Alaska, LLC I (019
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503 l ) C,
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Date: 12/19/2023
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 213-26
- PTD 223-069
- API 50-283-20192-00-00
Washed and Dried Well Samples (10/07/2023)
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 213-26
BOX 1 OF 3
2820' - 4500' MD
BRU 213-26
BOX 2 OF 3
4500' - 6000' MD
BRU 213-26
BOX 3 OF 3
6000' — 7200' MD
Please include current contact information if different from above.
RECEIVED
09C 19 2023
AOGCC
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received (/ Date:, (zo
/
Nolan Vlahovich Hilcorp Alaska, LLC
GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/18/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 213-26
- PTD 223-069
- API 50-283-20192-00-00
CBL 10/19/2023
PDF
LAS
Folder Contents:
Please include current contact information if different from above.
PTD: 223-069
T38220
12/8/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.08
15:46:34 -09'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Beluga River Unit
GL: 79.7' 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 2,530'
4-1/2" L-80 6,679'
4-1/2" L-80 2,363'
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:
01.2422 0
11/29/2023 24
Flow Tubing
1.2
3041
N/A30410
N/A
N/A
N/A
7,200' MD / 6,683' TVD
7,112' MD / 6,597' TVD
1792' FSL, 314' FEL, Sec 27, T13N, R10W, SM, AK
2416' FSL, 222' FEL, Sec 27, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
2,705'
2,352'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
11/12/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
317644
317745
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 213-26October 7, 2023887' FSL, 757' FWL, Sec 26, T13N, R10W, SM, AK
98.2'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2626952
SETTING DEPTH TVD
2627574
TOP HOLE SIZE
CBL 10-19-23, Mudlogs, LWD (AGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs
Sterling - Beluga Gas Pool
AKA029657
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
318697 2626036
50-283-20192-00-00September 23, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
11/5/2023 223-069 / 323-559
N/A
PACKER SET (MD/TVD)
Conductor
9-7/8"
Driven
Surface L - 402 sx / T - 173 sx
12.6#
Surface
Surface
2,888'
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,693' 7,196'
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 - 371 sx / T - 99 sx6-3/4"
2,705'4-1/2"
SIZE DEPTH SET (MD)
2,693' MD / 2,351' TVD
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 James Brooks at 1:31 pm, Dec 05, 2023
Completed
11/5/2023
JSB
RBDMS JSB 121923
G
223-069 / 323-559
DSR-1/26/24BJM 1/16/24
BRU 213-26
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel F 4711' 4277'
3936' 3529'
3983' 3574'
4191' 3773'
4585' 4156'
5118' 4671'
5499' 5039'
6298' 5810'
6879' 6373'
Beluga J3 7054' 6543'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
INSTRUCTIONS
Bel H
Bel I
Wellbore Schematic, Drilling and Completion Reports, Perf Reports, Definitive Directional Surveys, Csg and Cmt Report
Authorized Title: Drilling Manager
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Bel F
ST C5
Bel 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.
Bel J
Bel D
TPI (Top of Producing Interval).
Authorized Name and
Bel 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
12/05/23
Monty M
Myers
Updated by CJD 12-4-23
SCHEMATIC
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112’ MD / 6,597’ TVD
TD = 7,200’ MD / 6,683’ TVD
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 2,888’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,693’ 7,196’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,705’
3
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,529’ 3.958” 4.500” Chemical Injection Sub
2 2,693’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 6,164’ - - CIBP w/ 35’ of cement on top (11/9/23)
6-3/4”
hole
2
1
PERFORATION DETAIL
Sands Top
MD
Btm
MD Top TVD Btm TVD FT Date Status
Beluga F4 4711 4723 4277 4288 12 11/13/2023 Open
Beluga F5 4731 4736 4296 4301 5 11/13/2023 Open
Beluga F6 4776 4790 4340 4353 14 11/13/2023 Open
Beluga F6 4831 4839 4393 4400 8 11/13/2023 Open
Beluga F6 4860 4866 4421 4426 6 11/13/2023 Open
Beluga F7 4983 4987 4539 4542 4 11/13/2023 Open
Beluga F7 4999 5003 4554 4558 4 11/13/2023 Open
Beluga F7 5011 5016 4566 4570 5 11/13/2023 Open
Beluga F10 5062 5065 4615 4617 3 11/13/2023 Open
Beluga F10 5084 5087 4636 4639 3 11/13/2023 Open
Beluga F10 5111 5113 4662 4664 2 11/12/2023 Open
Beluga G1 5150 5155 4700 4704 5 11/12/2023 Open
Beluga G2 5165 5168 4714 4717 3 11/12/2023 Open
Beluga G3 5204 5209 4752 4757 5 11/12/2023 Open
Beluga G4 5264 5267 4810 4812 3 11/12/2023 Open
Beluga G6 5316 5339 4860 4882 23 11/11/2023 Open
Beluga H 5513 5519 5050 5056 6 11/11/2023 Open
Beluga H 5524 5534 5060 5070 10 11/11/2023 Open
Beluga H2 5612 5620 5146 5153 8 11/11/2023 Open
Beluga H3 5656 5660 5188 5182 4 11/10/2023 Open
Beluga H6 5783 5789 5311 5317 6 11/10/2023 Open
Beluga H7 5803 5813 5330 5340 10 11/10/2023 Open
Beluga H7 5819 5827 5346 5353 8 11/10/2023 Open
Beluga H7 5830 5845 5356 4371 15 11/10/2023 Open
Beluga H9 5880 5883 5405 5407 3 11/10/2023 Open
Beluga H10 5909 5918 5433 5441 9 11/10/2023 Open
Beluga H15 6214 6224 5727 5737 10 11/5/2023 Isolated
Beluga I4 6502 6512 6005 6014 10 11/5/2023 Isolated
Beluga I11 6763 6772 6258 6266 9 11/5/2023 Isolated
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2” Pumped 165 bbl 12# lead, 19 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
CBL TOC @ ~2.700’ MD.
Activity Date Ops Summary
9/21/2023 Brought in second crane and trucks, removed HandyBerm, tore out boiler skids, catwalk, pits, lowered doghouse, tore out 40' connex, clam shell, pumps, jig,
doghouse and HPU skid. Shipped out rig mats and jig, staged crane and removed iron roughneck, tore out gen skid.;Staged second crane, RU and removed
derrick from carrier. Sent notice to BLM, AOGCC and Quadco for upcoming diverter function test.;Removed carrier from sub, sub from pony walls, loaded pony
walls on trailer, transported all along with cranes to H pad.;On H pad, set pony walls and test pump, staged sub base and cranes, set sub on pony walls and
centered over well, set carrier on sub, set and pinned derrick on carrier. Set pits 1-2, set doghouse, set jig and gen skid, set pump #1, scoped up doghouse,
cleaned and folded liner on H pad for production;Set pit 3, set HPU skid, pump #2 and clam shell, disposed of felt on K pad, lay felt liner and mats f/ catwalk, set
catwalk into position and raise ramp, raise derrick into position and pin, fold down derrick board, raise pit rooves and pin, hook up lines between pits, set
centrifuge and dump tank;Raise gas buster and pin, hook up electrical lines and get power going through rig, get light on roof tops, fire up gens take on
fuel;Hook up modules and prep to scope derrick, run power and hydraulic lines to sub, R/U pason system, hook up drive shaft, inspect derrick, spot in third party
shacks and set water tank, fill water tank on rig and upright, continue R/U pit systems, and mud pumps, spool up drilling line and unchain;P/U and secure torque
tube to upper section, Scope derrick into drilling position and pin.
9/22/2023 Prepped and scoped derrick, RD office trailers on K pad, load and transported rig mats to H pad, laid out rig mats to set trailers on, installed T bar and
turnbuckles on lower torque tube, bermed in rig footprint, welder worked various projects, transported trailers to H pad. Set service shacks.;Powered up service
shacks, set office trailers and change shack, strung cords and set sewer tanks, changed camp gen oil and powered up trailers, cont welding projects, staged
topdrive on rig floor and transferred to blocks, hung windwalls on pits, function tested mix pumps, brought in DP bunks.;Installed new sock on service loop,
installed service loop on top drive, function test top drive, install saver sub and clamp, install wind wall frames on floor handrails, remove shipping beams and
catch can, set annular on diverter T, Build spud mud. Get RKBS Bottom of flange 21.89' GL 18.87'.;Continue N/U diverter Assembly, install knife valve and vent
line, Riser and flow line, install bails and elevators, rig tongs catwalk stairs, Continue building spud mud and working on rig acceptance checklist.
9/23/2023 Cont working through rig acceptance checklist, troubleshoot screw compressor (air), ordered out new electric motor (coming this afternoon), test and compare
torque values on TD, IR and rig tongs, adjusted service loop hyd S pipe and installed omni wrap over new sock, dressed floor with TIW/dart/XOs;finished last of
378 bbls spud mud, functioned diverter, staged blockades and signs, acceptance checklist complete at 12:30 and accepted rig, start loading pipe rack with 4
1/2" DP.;Performed diverter function test with joint 4 1/2" DP, draw down test, Quadco Rep tested gas alarms, measured vent line, tested PVT's and flow show,
staged barricades and warning signs. BLM waived witness at 10:52 am, cont rack and tally DP.;Adjusted torque tube with hanging joint to center in rotary table,
CCI racked surface casing, PU and racked back 50 stnds 4 1/2" DP and 9 stnds 4 1/2" HWDP and jars in mousehole and racked back. Mechanic and electrician
C/O screw compressor electric motor. Drift surface casing.;M/U BHA as per DD/MWD, upload MWD shallow test tools valve on MP leaking.;Replace 4'' Valve
on number 2 MP, test pumps good.;Drill Ahead 9 7/8'' Surface Hole f/ 138' t/ 624' 400 gpm 916 psi SPP 40 rpm 3k tq on bottom 10 k WOB 36k PUW 34k SOW
36K ROT MW 8.8 ppg ECD 9.4 ppg Distance to Plan 5.28' 5.28' High .02' Right.
9/24/2023 Cont drilling surface hole from 624' to 1260', sliding wob 1-10K, 407 gpm-944 psi, 39 psi diff, 300 ft/hr ROP. Rot wob 1-2K, 405 gpm-1040 psi, 55 rpm-4532 ft/lbs
on bott torque, 130 ft/hr ROP. MW 8.9/vis 153, ECD's at 9.9 ppg, BGG 0.;Sent BLM and AOGCC upcoming casing, cementing and initial BOP test
notifications.;Cont drilling to wiper trip depth from 1260' to 1444'. Rot wob 1-2K, 400 gpm-1021 psi, 55 rpm-4229 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob
9-12K, 393 gpm-1090 psi, 56 psi diff, 345 ft/hr ROP. MW 8.9/vis 251, ECD's at 9.8 ppg, BGG 0.;Obtained on bott survey, CBU twice at 409 gpm-1065 psi, 60
rpm-4400 ft/lbs off bott torque. Flow check = static.;Pulled up hole on elevators from 1444' to 1370', up wt 50K. At 1370' over pulled to 80K. Tried to work
through on elevators (9 dogleg), MU topdrive and back reamed twice to 1319', then worked through on elevators both ways with no issue. Cont to pull up hole to
362' (jars) and parked string.;Serviced rig and topdrive, shimmed sub base on draw works end.;TIH on elevators from 362' to 1291' and set down hard numerous
times (top of 9 dogleg). MU topdrive, filled pipe, washed and reamed stand twice, then worked on elevators with no issue. Washed and reamed last two stands
to bottom.;CBU at 429 gpm-1305 psi, 55 rpm-4238 ft/lbs off bott torque.;Cont drilling surface from 1444' to 2065' 384 gpm 1135 psi SPP 56 rpm 6.3k tq on
bottom, 1-3k WOB Dif 20 PUW 60k SOW 38k ROT 45k.;Continue Drilling Ahead 9 7/8'' Surface Hole f/ 2065' t/ 2496' 384 gpm 1190 psi SPP 50 rpm 6.5k TQ on
bottom, PUW 64k SOW 40k ROT 47k MW 9 ppg ECD 9.5 ppg Distance t/ Plan 15.68' 13.53' High 7.92' Right.
9/25/2023 Cont directional drilling 9 7/8" surface from 2496' to 2851'. Rot wob 1-3K, 400 gpm-1319 psi, 50 rpm-8690 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 2-6K,
401 gpm-1317 psi, 99 psi diff, 225 ft/hr ROP. MW 9.1/vis 210, ECD's at 9.6 ppg, BBG 0.;At 2775' ROP dropped to 11 ft/hr. Worked pipe (backreamed) with no
increase. Started increasing wob at 2784' to 17K seeing 70 to 134 diff pressure, 9 to 20 ft/hr ROP.;Cont drilling from 2851' to TD at 2895' md/2536' tvd. Rot wob
18K, increased pump rate to 500 gpm-1900 psi, increased 70 rpm-7100 ftlbs on bott torque, 5 to 50 ft/hr ROP. Added 3 sacks nut plug to suction pit with no
noticble change in ROP.;Sliding wob 13K, 505 gpm-1928 psi, 176 psi diff, 7 to 42 ft/hr ROP. MW 9.1/vis 202, ECD's at 9.6 ppg, BBG 2 units. TD'd in 75% clay,
20% sand, 5% carbonaceous material.;CBU one time at 506 gpm-1710 psi, 70 rpm-9800 ft/lbs off bott torque, then obtained on bottom survey (5.18' high and
8.35' right of the line) flow check = static.;L/D single jnt, pulled up hole on elevators from 2863', up wt 85K, to 329' (jars), then S/O and parked string at 394'. No
issue at 1370' (9 dogleg). Calc hole = 18.38 bbls, actual hole fill = 23.54 bbls.;Serviced rig and topdrive. Tightened service loop hyd line in derrick at board,
changed oil filters on floor motor.;TIH on elevators from 394' to 2895' with no issues, washed last stand to bottom no fill.;Pump Hi Vis Sweep around 496 gpm
1496 psi, sweep back 800 stks late and 30% cuttings return.;POOH f/ 2895' t/ 138' on elevators with no issues.;L/D Jar stand and collars , Down load MWD, L/D
BHA, Bit graded 1-1 in gauge.;R/U Parker Casing equipment, hold PJSM.;P/U float equipment and baker lock connections, float collar cross threaded backed
out slow and fixed threads M/U and check floats, good Continue RIH t/ 208'.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 213-26
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00093 BRU 213-26 Drilling
Spud Date:
gp
Drill Ahead 9 7/8'' Surface Hole f/ 138' t/ 624'
N/U diverter Assembly
9/26/2023 Cont PU single in hole with 7 5/8 TXP/BTC 29.7# L-80 surface casing from 208' to 1425' with no issue. Down wt 35K. MU circ swedge and topdrive.;CBU at 114
gpm-42 to 0 psi.;Cont PU and single in hole from 1425' to 2860' with no issue. At 2860' installed bale extensions on topdrive, installed circ swedge in landing
joint, PU and MU landing joint on stump, MU topdrive, broke circ at idle while RD casing tongs.;Staged up to 5 bpm-86 psi, washed down and landed hanger on
seat with no issue. Up wt 88K, dwn wt 44K. CBU while staging cement trucks, removed tongs from floor, staged plug launcher and loaded plugs. Shut down
pump, broke off topdrive, MU plug launcher and cement hose.;Cont circulating and held PJSM with rig team and cementers. shut down pump and lined up to
pump truck.;Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 697 psi low 4306 psi high, good tests.
Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 4 bpm-188 psi, dropped bottom plug and pumped 175 bbls (402 sx) 12 ppg Type I II;lead cement at 4
bpm-188 to 300 psi, followed by 34 bbls (173 sx) 15.8 ppg Type I II tail cement at 4 bpm-300 to 324 psi. Halliburton dropped top plug then displaced with 9.1 ppg
Spud Mud at 4.2 bpm 177 to 645 psi. Slowed pump to 3 bpm with 15 bbl to go.Did bump the plug 129 bbls;into displacement (calculated 129 bbls). Held 1408
psi (FCP of 742 psi) for 3 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 60 bbls of Spacer returns to surface and 74 bbls lead cement to
surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix water temp 50;deg. Pumped 75% excess on lead and 50% on tail. Lost 0 bbls throughout the
job. Did reciprocate casing. Up wt 100K, dwn wt 40K upon landing hanger at start of tail. CIP at 15:56 hrs, 9/26/2023. RD and released Halliburton.;Broke off
cement hose and L/D plug launcher, flushed diverter stack into cellar box with black water, B/O landing jnt and rinsed clean, L/D landing jnt, L/D bale extensions.
PU jnt DP and diffuser, MU topdrive and flushed stack down flow line and into cellar box with black water.;RD diverter vent line and knife valve, RD flow line and
riser, removed annular, removed diverter "T" and adaptor flange and staged in cellar for crane. Brought in crane and staged at cellar. Removed annular and "T"
assembly from cellar, staged wellhead and BOP stack;in cellar. Hauled off Spud mud to G&I. Worked on cleaning tank bottoms in pits 1&2.;Installed well head
as per WHR, torqued lock down bolts to 650 ft/lbs. Tested between well head seals T/5000 psi for 10 min (ok). Obtained RKB - 19.79'. Hung flow box. M/U
spacer spool to well head. Trolleyed in BOP stack on bridge cranes and N/U to spool. Greased choke manifold.;Crew change, held PTSM. Cont. w/ N/U.
Finished cleaning of tank bottoms, started mixing 2nd batch of new 6% KCL PHPA mud. M/U kill & choke lines and MGS line. M/U bell nipple to annular,
installed riser, flow line, and inflated air boots. installed HYD koomey lines;to stack. Energized koomey. installed test plug and jt. function test BOP's.;Flooded
stack, lines, and choke manifold w/ water, purged out air. Attempted to shell test. Currently hammering up leaks.
9/27/2023 Flood surface lines, tightened flow riser, purged air, shell tested stack, choke manifold and topdrive to 3500 psi, bled off, wait on Otter to arrive with Quadco and
AOGCC Reps, strapped 100 jnts DP, cleaned cellar and rig floor.;Quadco and AOGCC Reps on location at 09:00. Tested audio/visual gas alarms and released
Quadco Rep, tested all BOPE at 250 low for 5 min, 3500 high for 10 min, functioned PVT's and flow show alarms. Had one F/P on manual choke valve low test
on stack. Greased and cycled, re-tested ok.;Removed test plug, set wear ring, RU to test surface casing. Flooded stack and purged air. Closed blinds.;Pumped
72.5 gallons to achieve 3598 psi and held 30 minutes on chart. Bled back 72.5 gallons.;Leveled sub base, serviced rig and topdrive.;MU mule shoe, PU singled
in hole with 68 jnts 4 1/2" DP to 2044'. POOH racked back 34 stands in derrick.;M/U 6.75" directional BHA #2 as per Sperry. 6.75" HDBS PDC bit, Mud motor w/
1.5 degree bend. Measured off set = 332.89 degrees. M/U MWD tools to TM collar. Uploaded MWD data. Performed shallow pulse test (ok).;Crew change, held
PTSM. Held PJSM on loading sources, loaded sources. P/U remainder on BHA #2 T/741'.;Miss placed drift, POOH F/741' to top of flex collar. Recovered drift in
HWDP on top of flex collars. RIH w/ remainder of BHA #2.;P/U and singled in the hole w/ 6.75" BHA #2 F/741' to current depth of 1951'. P/U-48K S/O-35K.
9/28/2023 Filled pipe at 1951' and cont to PU single in hole with 4 1/2" DP and 6 3/4" directional BHA to 2769' and encountered cement stringer. PU to 2760', MU topdrive,
filled pipe. Washed and reamed down and tagged wiper plugs at 2800. 0 wob, 151 gpm-457 psi, 30 rpm-6400 ft/lbs torque.;Drill out wiper plugs, FC, shoe track,
shoe and rathole cement from 2800' to 2895', rot wob 5K, 145 gpm-624 psi, 30 rpm-5700 to 6000 ft/lbs torque.;Cont drilling new formation from 2895' to 2915',
202 rot wob 4K, 202 gpm-1416 psi,30 rpm-6300 ft/lbs on bott torque, 130 ft/hr ROP. At 2915' CBU. Cuttings sample revealed 70% coal, 25% sand, 5% clay.
Held PJSM on displacing well to new mud.;Pumped hi-vis spacer followed with 6% KCL mud, taking returns to cuttings box until good mud to surface, then CBU
twice more.;Racked back one stand pulling into casing and parking bit at 2875'. MU TIW and head pin on stump, RU test pump on kill and head pin, flooded
surface equipment and purged air, closed upper rams. Pumped 25 gallons to achieve 692 psi in attempt to obtain a 14.3 EMW. Held 15 minutes on
chart.;Pressure bled down to 346 psi and we bled back 8 gallons. Sent data to town, RD test equipment, PU single, MU topdrive on stand to circ but decision
made to perform a second LOT.;LD single, racked back stand, parked bit again at 2875'. RU TIW and head pin on stump, RU test pump on kill and head pin,
flooded surface equipment and purged air, closed upper rams. Pumped 22.5 gallons to achieve 689 psi in attempt to obtain a 14.3 EMW. Held 15 minutes on
chart.;Pressure bled down to 289 psi and we bled back 7 gallons. Sent data to town and WOO.;Installed tarps on pit openings, drifted 4 1/2" liner/tieback
pipe.;Approved to drill ahead. RD test equipment, PU single, MU stand and topdrive, eased down and resumed drilling 6 3/4" hole from 2915' to 2927'.;Cont.
directional drilling 6.75" production hole F/2927'-T/3280'. P/U-80K S/O-44K ROT-53K GPM-200 SPP-1150 psi RPM-40 TQ-7.2K Diff-52 psi WOB-1/2K MW-9.1
ppg ECD-10 ppg Max gas -150 units. Obtained new SPR's @ 3093'.;Crew change, held PTSM. Cont. directional drilling 6.75" production hole F/2927' to current
depth of 3650'. P/U-83K S/O-45K ROT-57K GPM-212 SPP-1250 psi RPM-60 TQ-8.5K Diff-111 psi WOB-1/2K MW-9.2 ppg ECD-10.1 ppg Max gas -114 units.
Pumped Hi-Vis;sweep w/ condet & walnut @ 3403', sweep came back on time w/ 30% increase in cuttings. Distance to well plan: 7.39' 7.03' High 2.29' Left.
9/29/2023 Cont drilling 6 3/4" hole from 3650' to 3897', rot wob 2-3K, 205 gpm-1316 psi, 60 rpm-8800 ft/lbs on bott torque, 110 to 120 ft/hr ROP. Sliding wob 2K, 201 gpm-
1342 psi, 203 psi diff, 155 ft/hr ROP. MW 9.1/vis 58, ECD's at 10.1 ppg, BGG 47, max gas 223 units.;On bottom survey = 3860' md, 16.39 Inc, 4.83 Azi, 3454'
tvd has us 5.75' high and 1.19' right of the line.;CBU at 212 gpm-1172 psi, 60 rpm-8720 ft/lbs off bott torque. Obtained on bottom survey, new SPR's and flow
check = slight seepage.;Pulled up hole at 20 ft/min from 3897' to 2847', up wt 95K, no issues, S/O and parked at 2906'. Calc hole fill = 7.36 bbls, actual hole fill =
6.73 bbls.;Serviced rig and topdrive, checked rineer motor bolts on topdrive, C/O saver sub. Moitored well on trip tank, loss rate at 1.2 bph.;Mad passed from
2922' to 3093' at 202 gpm-1037 psi, 46 rpm-6300 ft/lbs off bott torque.;TIH from 3093' to 3834' with no issue. MU topdrive, filled pipe, started 20 bbl hi-vis
nutplug sweep down drill string, washed and reamed to bottom at 3897'.;Pumped sweep around while rotating/reciprocating, 210 gpm-1156 psi, 60 rpm-7700 to
8500 ft/lbs off bott torque. Had a 20% increase in cuttings at bottoms up, another 50% increase with sweep to surface, back on time, max gas 66
units.;Resumed drilling from 3897' to 4023', rot wob 3-4K, 200 gpm-1082 psi, 60 rpm-8860 ft/lbs on bott torque, 80 ft/hr ROP. MW 9.1/vis 60, ECD's at 10.0 ppg,
BGG 57, max gas 229 units.;Adding 2.5 ppb each of BaroTrol plus and Soltex, 5 ppb Steelseal 50 (black product).;Cont. directional drilling 6.75" production hole
F/4023'-T/4289', flow decreased to 11%, picked up off bottom, slowed pump to 180 GPM. Flow stabilized at 11-15%. Cont. drilling ahead F/4289'-T/4457' w/
moderate returns. GPM-180 SPP-1150 psi RPM-60.;WOB-2K TQ-10K Diff-120/160 psi ROP-50/60 fph MW-9.15 ppg ECD-9.8 ppg Max gas-132 units. Dynamic
loss rate = 112 bph.;POOH to build mud volume. Obtained new SPR's. Flow check- well appeared to be breathing. Pump OOH due to well breathing F/4457' to
current depth of 3358'. GPM- 107 SPP-705 psi Flow-0/4%.;Distance to well plan: 2.74' 1.06' High 2.52' Right 497 bbls lost to hole over last 12 hrs.
q
Cont drilling new formation from 2895' to 2915',
pg p p pp
Pumped 25 gallons to achieve 692 psi in attempt to obtain a 14.3 EMW
pp j g
tested all BOPE at 250 low for 5 min, 3500 high for
p pgg
pumped 175 bbls (402 sx) 12 ppg Type I II;lead cement at 4 p p ppg p p p pp
bpm-188 to 300 psi, followed by 34 bbls (173 sx) 15.8 ppg Type I II tail cement
pp
bled off and floats held
pp pppp g p
Did bump the plug 129 bbls;into displacement (calculated 129 bbls
ggpg
POOH racked back 34 stands in derrick.;M/U 6.75" directional BHA #2 as per Sperry. 6.75" HDBS PDC bit, Mud motor w/j
1.5 degree bend
g
Did reciprocate casing
pg pppp
Pumped 22.5 gallons to achieve 689 psi in attempt to obtain a 14.3 EMW
)
Had 60 bbls of Spacer returns to surface and 74 bbls lead cement to
ppg p (
p(
surface Lost 0 bbls throughout
p p
Cont. directional drilling 6.75" production hole F/2927' to current ppg pp
depth of 3650'.
gp
Drill out wiper plugs, FC, shoe track,ppgpp gg p p g gp p p
shoe and rathole cement from 2800' to 2895', rot wob 5K, 145 gpm-624 psi, 30 rpm-5700 to 6000 ft/lbs torque.;
pp
Quadco and AOGCC Reps on location at 09:00.
second LOT.;
qp pg pp
Pressure bled down to 346 psi and we bled back 8 gallons. Sent data to town, RD test equipment
pg p p
p
CIP at 15:56 hrs,
SC cemented in place - no losses. -WCB
9/30/2023 Cont to pump OOH from 3358 to 2897 pulling at 20 ft/min. Pumped at 93 gpm-569 psi, 3% to 4% return flow, up wt 75K. At 109 gpm-601 psi, 9% return flow.
Building surface volume at 4% KCL.;At 2897' CBU twice at 115 gpm-568 psi, 30 rpm-6000 ft/lbs torque, BGG 20 units down to 14 units at shut down. Minimal
losses.;Cont building 300 bbls 4% KCL mud. Monitored well visually, fluid dropped 8" over 15 minutes then put well on trip tank with just under 2 bph loss
rate.;Circulated at 200 gpm-1121 psi, 10 rpm-5500 ft/lbs torque and had no losses. Reduce pump rate in 10 gpm increments to establish lowest pump rate we
can drill with (150 gpm lowest for mud motor). At 160 gpm have great detection. Increased to 240 gpm-1344 psi and had very little loss.;Put well on trip tank,
circulated with rig pump every hour for 10 minutes. Well took 2 bph on trip tank, cont building last 300 bbl batch of 4% KCL in premix tanks, staked for well on I
pad and measured for well on G pad.;Cont building 300 bbls 4% KCL in premix, monitor well on trip tank, circ for 10 minutes every hour. Static loss rate = 1
bph.;Finished rebuilding mud volume in active system. RIH F/2897'-T/4330' at 20 fpm. At 3810' started pushing away most on our pipe displacement. P/U-80K
S/O-42K.;Started seeing 5K drag going in the hole @ 4330' (cuttings bed). M/U TD, filled pipe. Washed/reamed F/4330'-T/4457' w/ no issues. P/U-80K S/O-43K
ROT-56K GPM-151 SPP-941 psi RPM-30 TQ-10.3K Flow-11/15% MW-9.1 ppg ECD-9.9 ppg Max gas- 54 units.;Pipe displacement- Cal-29.28 bbls Act-19.78
bbls Diff-9.5 bbls.;CBU- GPM-151 SPP-950 psi RPM-30 TQ-10.5K Flow-16% MW-9.1 ppg ECD-10.0 ppg Max gas- 102 units.;Resumed drilling 6.75" production
hole F/4457' to current depth of 4590'. P/U-82K S/O-47K ROT-61K GPM-157 SPP-1006 psi RPM-60 TQ-10.7K WOB-2/6K Diff-120 psi Flow-13/15% MW-9.15
ppg ECD-10 ppg Max gas- 54 units.;Distance to well plan; 4.6' 2.37' Low 3.94' Right Current loss rate= 15 bph. Total losses for the last 24 hrs. = 61 bbls.
10/1/2023 Cont directional drilling from 4590 to 4797', rot wob 1-4K, 154 gpm-1032 psi, 60 rpm-10,400 ft/lbs on bott torque, 50 ft/hr ROP. Sliding wob 3K, 154 gpm-1035
psi, 110 psi diff, 57 ft/hr ROP. MW 9.1/vis 64, ECD's at 10.0 ppg, BGG 32 units, max gas 227 units.;At 4627' started seeing losses despite full returns. At 4643'
loss rate at 20 bph that eventually got better as we drilled ahead.;Cont drilling from 4797' to 4952'. Rot wob 3K, 155 gpm-1102 psi, 60 rpm-11,000 ft/lbs on bott
torque, 50 ft/hr ROP. Sliding wob 1-3K, 154 gpm-1035 psi, 110 psi diff, 57 ft/hr ROP. MW 9.1/vis 60 , ECD's 10.1 to 10.2 ppg, BGG 27 units, max gas 115
units.;After drilling down to 4890', went to backream for connection, packed off immediately, lost return flow, slacked off reducing pump rate, recovered flow,
backreamed in 1' intervals until hole cleaned up, then a second time clean.;Dumped 3 sacks nutplug in suction pit and circulated surface to surface at 154 gpm-
936 psi, 60 rpm-10,300 to 12,000 ft/lbs off bott torque, max gas at bottoms up 127 units that came down to 11 units. (pill pit full of LCM pill), obtained SPR's.
ECD's down to 10.0 ppg.;Cont. drilling 6.75" production hole F/4957'-T/5202'. P/U-90K S/O-46K ROT-62K GPM-155 SPP-1080 psi RPM-60 TQ-11.5K WOB-
2/6K Diff-140 psi Flow-15% MW-9.25 ppg ECD-10.2 ppg Max gas- 298 units.;Cont. drilling 6.75" production hole F/5202' to current depth of 5387'. P/U-100K
S/O-45K ROT-63K GPM-153 SPP-1093 psi RPM-60 TQ-12.2K WOB-2/6K Diff-120 psi Flow-15% MW-9.25 ppg ECD-10.3 ppg Max gas- 173 units.;Distance to
well plan; 7.86' 6.41' Low 4.55' Right Current loss rate= 2 bph. Total losses for the last 24 hrs. = 83 bbls.
10/2/2023 Cont drilling 6 3/4" hole from 5387' to 5449' md/4988' tvd (G8 or 9). Rot wob 3-6K, 153 gpm-1114 psi, 60 rpm-11,900 ft/lbs on bott torque, 50 ft/hr ROP. MW
9.3/vis 56, ECD's at 10.3 ppg, BGG 78 units, max gas 290 units. Seeing 2 bph loss rate while drilling.;CBU x 2 at 153 gpm-986 psi, 60 rpm-12,270 ft/lbs off bott
torque, MW 9.3/vis 58, ECD's 10.3 ppg, max gas 95 units. Obtained on bottom survey and SPR"s, 10 minute flow check fluid dropped 1' in wellbore.;Pulled up
hole pumping from 5449' for wiper trip at 100 gpm-592 psi, 10% flow, up wt 95K. At 4835' could not pump or pull through tight spot, started backreaming at 30
rpm, 10 ft/minute working through numerous tight spots. At 4580' we lost all returns with no pressure spike or tight spot.;Reduced pump rate and put hole fill
pump on line as well. Got flow back at 10% with both pumps on hole. With only rig pump fluid static no returns without hole fill pump. Cont back reaming from
4580' to 4205' with occasional tight spots. S/O and parked at 4241' (previous loss zone at 4289').;Pumped and spotted 25 bbls of 45 ppb LCM pill (55 ppb
including background LCM), at 100 gpm-599 psi seeing 7 to 9% return flow with both rig pump and hole fill pump on. As pill exiting bit increased to 120 gpm-705
psi, 9% flow to push pill down hole.;With pill spotted, flow check = fluid dropped about 2' in wellbore in just a minute. S/O on drill string and fluid also dropped,
PU on drill string, fluid also rose. Dumped 3 sacks nutplug in suction pit to cont backreaming up hole. Start building volume in pre-mix.;Cont backreaming up
hole from 4241' to 3835' then able to pump and pull with no rotary, occasional tight spots, still had to run rig pump and hole fill to get returns. At 3598' able to pull
nice and clean, no further tight spots, pumping at idle. Parked at 2903'. Did not see;any LCM on shakers, but did see nut plug on shakers while backreaming.
Lost 654 bbls over last 12 hours. BLM Rep Allie Schoessler arrived on location @ 14:00 hrs. and did a rig site inspection.;CBU at 208 gpm-1232 psi, 13 rpm-
5700 ft/lbs, 8 to 15% returns with rig pump only. Max gas 32 units. Cont building volume.;Cont to build volume while monitoring well on trip tank. Lost .84 bbls
over 1.5 hrs. Decision made to POOH and change out BHA to cleanout/cementing BHA.;POOH on elevators F/2903'-T/BHA at 741'. Racked back HWDP, jar
std, and flex collar. Removed sources. Down loaded recorded MWD data.;Crew change, held PTSM. L/D remainder on BHA #2. Bit graded 1-2 in gauge.
Calculated hole fill- 25.94 bbls Act- 55.78 bbls Diff- 32.3 bbls. Cont. working on building mud volume.;Cleared & cleaned rig floor. Staged cementing BHA #3 on
the catwalk while monitoring hole on TT. Loss rate- 1 bph.;P/U cementing BHA #3- 6.75" Tricone bit, bit sub w/ float (dart style), integral blade stabilizer, jars,
and HWDP.;RIH on elevators F/567'-T/casing shoe - 2856' at 30 fpm. P/U-32K S/O-30K Calculated pipe Disp.- 56.1 bbls Act- 14.62 bbls Diff- 41.48
bbls.;Monitored well on TT, loss rate= xx bph while performing rig service- Greased & inspected crown, TD, wash pipe, IR, blocks, DWKS, brake linkage, and
drive shaft.;Cont. working on mixing mud volume and building a 30 bbl LCM pill w/ 90 ppb of LCM material. Monitoring well on TT and breaking circulation every
hour. Distance to well plan: 7.52' 5.55' Low 5.03' Right. Current static loss rate= .5 bph.;Dynamic loss rate= 48 bbls Total losses for the last 24 hrs.= 748 bbls.
10/3/2023 Continue mixing mud & building volume. Build a 30 bbl LCM pill w/ 90 ppb of LCM material. Monitoring well on TT & breaking circulation every hour Dynamic
loss rate F/ 48 BPH T/ 36 BPH @ GPM 78 SPP 128/ 114 psi. Weekly function test @ 2856' with everything except Blind Rams.;RIH F/ 2856' T/ 4501' P/U 78K
S/O 44K.Calculated displacement 11.5 BBLs Actual displacement 11.18 BBLs.;Pump 30BBLs of 90PPB LCM pill at GPM 78 SPP 140/ 200psi.;POOH F/ 4501'
T/ 3786' P/U 78K S/O 44K. First 150' pulled was overbalanced on the backside. Calculated hole fill 5.52 BBLs Actual hole fill 3.01 BBLs.;Monitor well on trip tank
& Service Rig. Static loss rate 3 BPH. Grease & Inspect Crown, Blocks, Top Drive, Draworks, Brake Linkage, Driveshaft, Iron Roughneck & Standpipe manifold.
Replace saver sub & install new grabber dies.;RIH F/ 3786' T/ 5449' washing last stand down to bottom. P/U 84K S/O 47K Calculated displacement 12.88 BBLs
Actual displacement 11.61 BBLs.;Circulated & condition mud, bringing it back up to 6% KCL. Mixed a 30 bbl LCM pill w/ 90 ppb of LCM materials. Cont. building
mud volume in premix pit. P/U-100K S/O-47K ROT-64K Gpm-164 SPP-433 psi TQ-10.2K RPM-30 MW-9.1 ppg ECD-9.9 ppg Max gas-206;units. Dynamic loss
rate= 40 bph.;Obtained new SPR's. Flow checked well. Attempted to POOH w/ no luck. Pumped OOH F/5449'-T/4212'. GPM-77 SPP-145 psi MW-9.1 Max gas-
3 units. Calculated hole fill- 9.2 bbls Act-25.05 bbls Diff-15.85 bbls;CBU- GPM-170 SPP-362 psi RPM-60 TQ-9K Flow-15% MW-9.1 ppg ECD-9.9 ppg Max gas-
15 units. Lost 15 bbls while CBU.;Crew change, held PTSM. Spotted 30 bbl LCM pill w/ 90 ppb LCM @ 4217'. GPM-120 SPP-191 psi Flow-11%. Lost 21 bbls
while spotting pill.;POOH on elevators F/4217'-T/3469' (12 stds). P/U-70K S/O-45K Calculated hole fill- 5.04 bbls Act-4.73 bbls Diff-.31 bbls;Circulated
on top of LCM @ 3469'. Lost 9.5 bbls before shutting down the pump. GPM-101 SPP-180 psi.;Attempted to POOH w/ no luck. Pumped OOH F/3469'-T/2852'.
P/U-58K S/O-42K GPM-78 SPP-126 psi MW-9.1 Max gas- 3 units. Calculated hole fill- 3.78 bbls Act-10.46 bbls Diff-6.68 bbls;Monitored well on TT while waiting
for LCM pill to soak and building mud volume. Static loss rate= 3 bph.;RIH on elevators F/2852' to current depth of 3908' w/ no issues. P/U-58K S/O-42K Total
losses for the last 24 hrs.= 238 bbls.
p
Mixed a 30 bbl LCM pill w/ 90 ppb of LCM materialsf
Cont drilling 6 3/4" hole from 5387' to 5449' md
q ggp
At 4627' started seeing losses despite full returns. At 4643'p p ppg g
loss rate at 20 bph that eventually got better as we drilled ahead.;Cont drilling from 4797' to 4952
qg p
Cont. drilling 6.75" production hole F/4957'-T/5202'.
Resumed drilling 6.75" production
hole F/4457' to current depth of 4590'.
Continue mixing mud & building volume. Build a 30 bbl LCM pill w/ 90 ppb of LCM materia
10/4/2023 RIH on elevators F/ 3908' T/ 5449' washing last stand down with 20' of fill. P/U 104K S/O 58K.;CBU while rotating & reciprocating to confirm loss rate has not
changed from 40 BPH Dynamically. RPM 30 GPM 78/ 170 SPP 249/ 500psi. TQ 10/ 11K P/U 104K S/O 58K ROT 75K. Flow check: Slight seepage.;Pump out of
the hole F/ 5449' T/ 4156' GPM 78 SPP 150psi. P/U 85K S/O 42K.;Replace grabber dies while monitoring well on trip tank. 0.5 BBL lost.;POOH on elevators F/
4156' T/ 2895' with no issues. P/U 62K S/O 43K. Calculated hole fill 16.8 BBLs Actual hole fill 23.59 BBLs.;Rig up equipment for lost circulation cement
job.;PJSM for Lost Circulation Cement Plug. Fill lines with water & test lines 975psi Low, 2980psi. High. Batch up & pump 40 BBLs 15.8ppg LCM cement @ 3
BPM, 210psi. 205 sks, Yield 1.161 ft3/ sk, WR 4.987 gal/ sk. No lift pressure while pumping.;Displace 39 BBLs 9.1ppg 6% KCL PHPA mud @ 4 BPM, 110psi.
Lost total of 27 BBLs during entire job. Break off cement hose configuration, Lay down 10' pup joint & POOH F/ 2895' T/ 2639'. CIP @ 13:06. Flush & clean
cement unit, R/D surface iron & crew depart location.;Grease & Inspect Crown, Blocks, Top Drive, Draworks, Brake Linkage, Drive Shaft, Iron Roughneck,
Standpipe manifold while monitoring well on trip tank.;Monitoring well on trip tank while allowing cement slurry to gain a consistency of 70 Bc. Static loss rate
down to 0.5 BPH.;Washed/Reamed F/2639'-T/4366'. F/3135'-T/3145' and again at 4333' it took 2-4K to wash/ream down (seen cmt at the shakers). P/U-52K
S/O-40K ROT-58K GPM-100 SPP-170 psi RPM-30 TQ-4.8K Flow-11% MW-9.2 ppg Max gas-11 units.;CBU @ 4366' due to float sticking and mud U-tubing. P/U-
78K S/O-44K ROT-58K GPM-105 SPP-325 psi Flow-11% MW-9.2 ppg Max gas-612 units.;Cont. to washed/reamed F/4366'. F/4531'-T/4590', took 2-4K to
wash/ream down (seen cmt/coal at the shakers). Washed/Reamed fill F/5433'-T/5449' (16'of fill on bottom). P/U-88K S/O-44K ROT-58K GPM-148 SPP-407 psi
RPM-30 TQ-7.7K Flow-16% MW-9.2 ppg Max gas-11.;Max gas-486 units. Calculated pipe displacement.- 14.7 bbls Act- 10.85 bbls Diff- 3.85 bbls.;CBU staging
up pump F/150-200 GPM with no real losses observed. P/U-96K S/O-44K ROT-65K GPM-200 SPP-542 psi RPM-60 TQ-12.5K Flow-16% MW-9.25 ppg Max
gas-58 units. Pumped 25 bbls Hi-Vis sweep w/ walnut, sweep came back on time w/ a 10%.;increase in cuttings. Added 4 drum of NXS lube to the system
behind the sweep to help lubricate the hole. Flow checked- slight seepage.;POOH on elevators F/5449' to current depth of 1315' w/ no issues and calculated
hole fill. P/U-32K S/O-32K Total losses for the last 24 hrs.= 167 bbls.
10/5/2023 POOH F/ 1315' T/ 567' BHA #3 P/U 29K S/O 29K.;POOH & stand back HWDP, L/D jars & 1 jt. HWDP, L/D Integral blade stabilizer, Bit sub & Tricone bit.
Graded 1-1. Calculated hole fill 40.8 BBLs Actual hole fill 43 BBLs. Clean & clear rig floor.;P/U & M/U BHA #4 6-3/4" Triple combo BHA, Bit, Motor, Scribe offset,
DM, PCG & ADR Collars, Change out ALD, P/U CTN Collar, PWD & TM Collar. Re-Position flow diverter on PWD & M/U TM Collar. M/U Top Drive & Download
MWD, Shallow Pulse test.;GPM 200 SPP 729 psi. PJSM & Load Nukes. M/U single jt. Flex Collar, 7 Jts. HWDP, P/U new Jars & 1 Jt HWDP & M/U 10
remaining HWDP Jts. P/U 33K S/O 32K. RFO=332.89.;RIH BHA #4 with 4-1/2" 16.60# S-135 CDS40 Drill Pipe F/ 740' T/ 5385' P/U 102K S/O 48K Calculated
displacement 42 BBLs Actual displacement 41.79 BBLs. Float was open occasionally during trip.;M/U Top Drive & washed down F/ 5385' T/ 5449' GPM 200
SPP 1250 psi. RPM 60. Obtain new SPRs @ 5449' MD 4988' TVD with 9.3ppg MW MP #1 15 SPM 313 psi. 30 SPM 456 psi. MP #2 15 SPM 325 psi. 30 SPM
445 psi.;Resumed directional drilling 6.75" production hole F/5449'-T/5759'.P/U-110K S/O-50K ROT-68K GPM-200 SPP-1500 psi RPM-60 TQ-12.7K Diff-280
psi WOB-7K Flow-17% MW-9.3 ppg ECD-10.1 ppg Max gas-231 units. Brought up lube concentration to 1.5% by vol.;Crew change, held PTSM. Cont.
directional drilling 6.75" production hole F/5759' to current depth 6067'. Pumped 25 bbl Hi-Vis sweep w/ walnut @ 5944', sweep came back 7.5 bbl early w/ a
50% increase in cuttings. P/U-120K S/O-52K ROT-74K GPM-202.;SPP-1684 psi RPM-60 TQ-14K Diff-304 psi WOB-4/7K Flow-17% MW-9.35 ppg ECD-10.4
ppg Max gas-667 units. Distance to well plan: 7.45' 7.22' Low 1.86' Right.
10/6/2023 Continue directional drilling 6.75" production section F/ 6067' T/ 6346' P/U 125K S/O 51K ROT 72K GPM 200 SPP 1170 psi RPM 70 TQ 15.5K Diff 290 psi
WOB 4/8K Flow 18% MW 9.4 ppg ECD 10.6 ppg Max gas 485 units.;Continue directional drilling 6.75" production section F/ 6346' T/ 6496' MD 5999' TVD P/U
128K S/O 50K ROT 70K GPM 200 SPP 1640 psi RPM 70 TQ 17K Diff 230 psi WOB 5/8K Flow 16% MW 9.5 ppg ECD 10.8 ppg Max gas 137 units.;CBU @
6496' P/U 128 S/O 50K ROT 72K GPM 200 SPP 1630 psi. RPM 60 TQ 16K Reciprocate & Rotate to get BU sample. SPRs @ 6496' MD 5999' TVD with MW
9.5ppg MP #1 25 SPM 482 psi. MP #2 23 SPM 441 psi.;Monitor well, Static. POOH F/ 6496' T/ 5387' on elevators. P/U 136K S/O 50K Calculated hole fill 7.14
BBLs Actual hole fill 6.45 BBLs.;Line up on trip tank & monitor well: 0.76 BPH loss rate. Grease & Inspect Crown, Blocks, Top Drive, Draworks, Brake Linkage,
Drive Shaft, Iron Roughneck & Stand Pipe Manifold.;RIH F/ 5387' T/ 6052' & set down 10K. M/U Top Drive. Calculated pipe displacement- 10.98 bbls Act- 10.75
bbl Diff- .23 bbls.;Wash & Ream F/ 6052' T/ 6496' Fill pipe GPM 150 SPP 1200/2200 psi. RPM 30 TQ 15/ 17K. Max Gas 3991 units.;CBU. GPM-202 SPP-1680
psi RPM-60 TQ-16K MW-9.5 ppg ECD-10.4 ppg Max gas-3858 units.;Made connection, pumped up survey. Pumped 25 bbl Hi-Vis sweep w/ walnut & condet
while cont. to drill ahead F/6499'-T/6624'. Sweep came back 24 bbl early w/ a 60% increase in cuttings. P/U-128K S/O-50K ROT-70K GPM-200 SPP-1800 psi
RPM-60 TQ-15.8K.;Diff-280 psi WOB-2/6K Flow-17% MW-9.55 ppg ECD-10.5 ppg Max gas-343 units. Brought up lube concentration to 2% by volume.;Crew
change, held PTSM. Cont. drilling 6.75" production hole F/5449' to current depth of 6869. Currently pumping 25 bbl Hi-Vis sweep.;P/U-135K S/O-50K ROT-74K
GPM-200 SPP-1790 psi RPM-60 TQ-15.5K Diff-280 psi WOB-6/7K Flow-17% MW-9.5 ppg ECD-10.8 ppg Max gas-117 units. Distance to well plan: 9.74' 7.35'
Low 6.38' Left.
10/7/2023 Continue directional drilling 6.75" production section F/ 6869' T/ 7200' MD 6683' TVD P/U 130K S/O 48K ROT 72K GPM 200 SPP 2100 psi RPM 60 TQ 16.7K
Diff 340 psi WOB 10K Flow 16% MW 9.5 ppg ECD 10.9 ppg Max gas 168 units.;CBU GPM 200 SPP 1610 psi. Flow 16% Max Gas 72 units RPM 60 TQ 17.5K
P/U 130K S/O 48K ROT 72K. Mud Loggers catch BU sample & share with Geologist. Geologist confirmed well is at TD. Shoot final survey for Sperry. Pump Hi-
Vis sweep, Sweep;came back 25 BBLs early with 10% increase in cuttings. SPRs at 7200' MD 6683' TVD MW 9.6ppg MP #1 SPM 25 SPP 482 psi. MP #2 SPM
25 SPP 472 psi. TD Extrapolated 7200' MD 6683' TVD Inc 12.54 Az 3.56 23.97' from wp04 18.87' Low 14.97' High.;Pump out of hole F/ 7200' MD T/ 5999' P/U
120K S/O 48K GPM 40/120 SPP 55/1000 psi. Packed off at 5999' & working through clay zone too erratic.;BROOH F/5999'-T/5442' working through an
occasional tight spot. P/U-120K S/O-60K ROT-78K GPM-150 SPP-1100 psi TQ-14.5K MW-9.6 ppg Flow-13% ECD-10.8 ppg Max gas-50 units.;Pumped 25 bbls
Hi-Vis sweep w/ walnut & condet. Hole unloaded at BU (100% increase). Sweep came back 7 bbls early w/ a 150% increase in cuttings. Circulated till shaker
cleaned up. P/U-105K S/O-48K ROT-66K GPM-203 SPP-1480 psi TQ-13K.;MW-9.65 ppg Flow-17% ECD-10.8 ppg Max gas-92 units.;POOH on elevators w/ no
issues F/5442'-T/2839' with calculated hole fill. Dropped metal drift on wire on std # 43. P/U-114K S/O-52K.;Monitored well on TT. Serviced rig- Inspected &
greased crown, blocks, TD, wash pipe, IR, brake linkage stand pipe manifold, and drive shaft.;Held PJSM. Slip & cut 95" of drill line = 20 wraps. Recalibrated
hook load & block height. Static loss rate= .43 bph.;POOH F/2839'-T/740' BHA #4. P/U-25K S/O-25K Calculated hole fill-34.5 bbls Act-36.12 bbls Diff- +1.62
bbls Recovered metal drift on wire at 800'.;L/D HWDP, Running FW and vacuuming wiper ball through tubular, re-doping threads. L/D jars, and flex collar.
Removed corrosion ring. Held PJSM on sources, removed sources. Down loaded MWD data. Currently L/D remainder of BHA #4.
p
Geologist confirmed well is at TD.
Continue directional drilling 6.75" production section F/ 6869' T/ 7200
10/8/2023 Continue laying down BHA #4. Bit graded 1-1-WT-A-X-I-NO-TD.;Clean & Clear rig floor, R/U TRS equipment along with proper drive sub crossover sub. 50
cementralizers brought to floor. R/U fill hose & confirm hydraulic tongs functioning properly.;PJSM, P/U & M/U Float Collar jt. to shoe jt with Baker-Lok Fill and
confirm floats working as designed. Good. Baker-Lok Landing collar jt. & Continue running 4-1/2" 12.6# L-80 Range III TXP/ BTC Liner F/ 126' T/ 4471' as per
tally filling as we run & topping off;every ten jts. Optimum TQ 6170 ft/lbs. Placing cementralizers on every other joint until 115' below 7-5/8" Casing Shoe. P/U &
M/U 3-1/2" X 4-1/2 X 7-5/8" HRD-E ZXP LTP W/ Flex Lock V Liner Hanger & install Pal mix between PBR & Running tool. RIH T/ 4579';& circulate liner volume
GPM 207 SPP 370 Flow 19% while removing hydraulic tongs from rig floor. Cont. RIH with stands of 4-1/2" CDS40 drill pipe F/ 4579' T/ 6955'.;Started taking
weight @ 6955'. M/U TD, filled pipe, Washed down F/6955'-T/7192'. M/U Baker cmt head, washed down and tagged bottom @ 7200'. P/U and set hanger shoe
on depth at 7196'. GPM-102 SPP-540 psi Flow-13%.;Circulated & conditioned mud while R/U HES cmt's. P/U-76K S/O-40K GPM-126 SPP-528 psi Flow-14%
MW-9.65 ppg. Held PJSM on cmt job.;Halliburton pumped 5 bbls of water to flush and fill lines. Shut in at Baker cement head and PT lines at 360 psi low 4850
psi high. Good tests. Lined up Baker cement head to Halliburton, pumped 30 bbls 10.5 ppg Tuned Spacer at 3 bpm-500-300 psi, followed with;165 bbls (371 sx)
12 ppg Type I II Lead cement at 3 bpm, 350 to 83 psi, followed with 19 bbls (99 sx) 15.3 ppg Type I II Tail cement at 3 bpm, 83 to 236 psi. Had 2 pps
Bridgemaker LCM in lead. Baker released dart, Halliburton then displaced with 9.65 ppg 6% KCL mud;mud at 3 bpm-60 psi ICP. Saw dart latch wiper plug 35
bbls into displacement with 599 psi. With 14 bbls to go, reduced rate to 2 bpm-1125 psi and bumped liner wiper plug/landing collar at 101 bbls into displacement
(calculated at 104 bbls). FCP 1168 psi. Halliburton;increased to and held 1597 psi (429 over fcp) for 1 minute, then increased pressure to 2500 psi for 1 minute
to set hanger. Bled back 1 bbls to truck and floats held. Slacked off on blocks from 40K to 15K, giving us a good indication ha nger was set. CIP at 12:27 on;10-9-
23. Pressured up to 4635 psi to set packer and released running tools. Seen good indication of packer setting. P/U to 35K with good indication of release. R/D
cmt hoses and L/D Baker cmt head. M/U TD to stump to circulate. Pressured up to 1035;psi on drill string and PU 13, pressure cont. to climb to 2178 psi with no
indication of dumping. Shut down pump. P/U additional 10' with no change in pressure. Bumped rotary, pressure dumped. CBU x3 at 343 gpm-351 psi. Had 30
bbls spacer and 4 bbls;cement/contaminated mud at the shakers. Lost all returns 60 bbls into displacement. Had a total of 78 bbls lost for the job.;POOH F/2652'-
T/hanger running tool. Inspected tool (ok). B/D tool and L/D same. Calculated hole fill- 20.7 bbl Act- 16.7 bbls Diff- 4 bbls.;Cleaned & cleared rig floor. M/U stack
washing tools on E-Kelley. Flushed stack w/ black water. L/D same. P/U and B/O pups & XO off Baker cmt head and L/D same.;P/U Baker PBR mill assembly.
RIH F/surface to current depth of 702'.
10/9/2023 Continue RIH with Baker PBR mill assembly F/ 702' T/ 2703' with Top mill @ 2693' Fill pipe & polish PBR as per Baker rep. P/U 35K S/O 30K ROT 32K GPM
127 SPP 147 psi RPM 26 Flow 13%. Calculated displacement 47 BBLs Actual displacement 47 BBLs.;Displace 9.65ppg 6% KCL PHPA with 8.4ppg Corrosion
Inhibited water after spacer GPM 340 SPP 404 psi. RPM 18 Flow 25% TQ 3.8K. Flow Check well: Static.;POOH F/ 2693' Laying down drill pipe, Pulling wiper
balls through pipe & re-doping connections & installing thread protectors. L/D Baker Polish Mill. Calculated hole fill 20.7 BBLs Actual hole fill 18.49 BBLs. P/U
30K S/O 30K.;RIH with mule shoe & drill pipe from derrick T/ 2476'. P/U 32K S/O 25K. Pumped through drill pipe with CI water to clean KCL Mud. Calculated
displacement 16.08 BBLs Actual displacement 16.19 BBLs.;POOH F/ 2476' Laying down drill pipe, Pulling wiper balls through pipe & re-doping connections &
installing thread protectors. L/D Baker Polish Mill. Calculated hole fill 16.16 BBLs Actual hole fill 17.62 BBLs. P/U 32K S/O 25K.;RIH 4.5" DP out of derrick
F/surface-T/2086'. POOH L/D 4.5" DP singles F/2086'-T/surface. Cleaning & re-doping threads. Vacuuming wiper balls through pipe. P/U-30K S/O-26K.;P/U test
jt & test plug. Pulled wear ring and L/D same. M/U well head brush tool on test jt. Cleaned out well head and L/D same.;R/U testing equip. Flooded lines and
purged out air. Tested casing/liner lap T/3500 psi on chart for 30 min (ok). Pumped in 2.5 bbls Bled back 2.5 bbls. R/D testing equip.;R/U TRS equip. Loaded
racks with tie back string. Held PJSM. P/U & M/U tie back bullet seal assembly as per Baker rep.;Crew change, held PTSM. Started running 4.5" 12.6# L-80
TXP/BTC tie back as per run tally F/surface-T/1169'.;P/U & M/U chem sub. R/U Pollard control line spool. M/U control line to chem sub. Tested connection
T/2000 psi for 10 min (ok). Cont. hold 1000 psi on control line while RIH.;Resumed running tie back string F/1181' to current depth 2598'. Installing band on pipe
to hold control line.
10/10/2023 Continue running tie back string F/ 2598' T/ 2707' & locate PBR with No-Go. Space out by laying 2 jts. down & P/U 2 8' pups. 2 4' pups, Make up hanger &
landing jt. Test Control line T/ 2500 psi. Good. Land hanger with mule shoe below seals at 2705'. 1.80' off of No-Go. 48 Total SS Bands.;Test between hanger
seals T/ 5000 psi. for 10 min. Good. Rotate landing jt. 6 rotations to left to lock hanger into place. Release pressure between hanger seals and rotate landing jt.
6 turns to the right. Pull Test T/ 40K with no movement. Good. Break out left hand landing joint & L/D.;R/U Test equipment for MIT's & purge all lines. Remove
Pollard control line tools from rig floor.;MIT= PT 4-1/2" Tie-Back/ Liner T/ 3650psi for 30 charted minutes. IA pressured up to 90 psi. Good Test. 1.4 BBLs to
pressure up, 1.3 BBLs bled back. PT 7-5/8" X 4-1/2" IA T/ 2500 psi for 30 charted minutes. Tbg. pressured up to 200 psi. 0.9 BBL to pressure up 0.85 BBL bled
back.;Rig down test equipment, Set TWC with dry rod, Flush Choke and kill line, choke manifold & gas buster with inhibited water. Rig down tongs & handling
equipment, Clear rig floor of crossover subs.;N/D flow line & bell nipple, N/D choke & kill lines, open rams doors, clean & inspect, Inspect pump seats & valves.
Lubricate ram door bolt holes with corrosion X & close BOPE doors. Cleaned last of tank bottoms. Rig down pumps, Move water tank & cement;silo. L/D
mousehole, Remove third party shacks. Pull windwalls & place in carrier.;N/D BOP Stack and remove, install wellhead as per wel lhead rep, test seals t/ 5000
psi f/ 10 min, shell test tree t/ 500 psi f/ 5 min good test, secure wellhead, clean cellar area.;install shipping beams in cellar, R/D top drive, remove bails and kelly
hose, remove saver sub and service loop.;R/D top drive put in cradle and remove from floor, remove torque tube, take off t bar and prep to scope derrick,
continue rigging down modules and prepping to move, lay over gas buster and blow down steam and water, scope down derrick remove lower torque tube.
gp p yp
Lost all returns 60 bbls into displacement
p
CIP at 12:27 floats held.
gqp qp
Started running 4.5" 12.6# L-80 g
TXP/BTC tie back as per run tally F/surface-T/1169'.;P/U & M/U chem sub
PT 7-5/8" X 4-1/2" IA T/ 2500 psi for 30 charted minutes
gj
PT 4-1/2" Tie-Back/ Liner T/ 3650psi for 30 charted minutesp
gp p y j j
Continue running 4-1/2" 12.6# L-80 Range III TXP/ BTC Liner F/
pg p p
and 4 bbls;cement/contaminated mud at the shakers
pyyg
Land hanger with mule shoe below seals at 2705
p gp
Had a total of 78 bbls lost for the job
gg g
Seen good indication of packer setting
p
with;165 bbls (371 sx)pg p pp ppg p p
12 ppg Type I II Lead cement at 3 bpm, 350 to 83 psi, followed with 19 bbls (99 sx) 15.3 ppg Type I II Tail cement at 3 bpm
gppgp
R/D top drive put in cradle and remove from floor, remove torque tube, take off t bar and prep to scope derrick,pp
continue rigging down modules and prepping to move,
Activity Date Ops Summary
10/16/2023 PJSM, Mob Equipment from K-Pad to H-Pad, Spot in & rig up
10/17/2023 PJSM, Discuss SIM ops on H pad & rigging up,Crew travel to location,Mob tanks to H-pad, set up containment and transport fresh water to tanks,,Pressure test
BOPE 250 low, 2500 high-good test,Crew travel to camp
10/18/2023 PJSM, Discuss daily operations running in hole with motor & displacing fluid (high pressure, rig up & down, working @ heights),Crew travel to location,Pick up
injector head & lubricator, Make up tool connector, Pull test to 15k & 30k pressure test to 3500 psi-good test
Make up bit & motor,Run in hole @ 100 ft/min to tag @ 7071',Kick in pump & establish circulation, Wash down to bottom @ 7112'.
Circulate 100 bbls out till fluid clean,Pull out of hole while pumping to 300' @ 300' kill pump,Bump up & rig down equipment
Secure well
Coil hand well over to e line,Spot in E-line & rig up
Pick up & make up CCL/CBL/Gamma
Pick up & make up lubricator,Pressure test lubricator to 250 low/2500 high-good,Run in hole to 2400', tools not working,Trouble shoot tools, decide to pull out of
hole and inspect at surface.,Pull out of hole & secure well,
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 213-26
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00093 BRU 213-26 Completion
Spud Date:
Coil hand well over to e line,Spot in E-line & rig up
Page 1/3
Well Name: BRU 213-26
Report Printed: 12/5/2023www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:11/5/2023 End Date:
Report Number
1
Report Start Date
10/16/2023
Report End Date
10/17/2023
Operation
PJSM, Mob Equipment from K-Pad to H-Pad, Spot in & rig up
Report Number
2
Report Start Date
10/17/2023
Report End Date
10/18/2023
Operation
PJSM, Discuss SIM ops on H pad & rigging up
Crew travel to location
Mob tanks to H-pad, set up containment and transport fresh water to tanks,
Pressure test BOPE 250 low, 2500 high-good test
Crew travel to camp
Report Number
3
Report Start Date
10/18/2023
Report End Date
10/19/2023
Operation
PJSM, Discuss daily operations running in hole with motor & displacing fluid (high pressure, rig up & down, working @ heights)
Crew travel to location
Pick up injector head & lubricator, Make up tool connector, Pull test to 15k & 30k pressure test to 3500 psi-good test \nMake up bit & motor
Run in hole @ 100 ft/min to tag @ 7071'
Kick in pump & establish circulation, Wash down to bottom @ 7112'. \nCirculate 100 bbls out till fluid clean
Pull out of hole while pumping to 300' @ 300' kill pump
Bump up & rig down equipment \nSecure well \nCoil hand well over to e line
Spot in E-line & rig up\nPick up & make up CCL/CBL/Gamma\nPick up & make up lubricator
Pressure test lubricator to 250 low/2500 high-good
Run in hole to 2400', tools not working
Trouble shoot tools, decide to pull out of hole and inspect at surface.
Pull out of hole & secure well
Report Number
4
Report Start Date
10/19/2023
Report End Date
10/20/2023
Operation
PJSM, discuss daily wireline & coil operations
Crew travel to location
Pick up Lubricator & test 250 low/2500 high-good, Perform CBL run to 7112', Log From 7112' to 2395', Pull out of hole & rig down. TOC @ 2700'
Spot in N2, Pick up Injector head & make up reverse nozzle.
Run in hole while unloading with N2 to recover 117 bbls of water.
Pull out of hole to surface Trapping 1000 psi
Pull out of hole to surface Trapping 1000 psi
End of day
Report Number
5
Report Start Date
11/3/2023
Report End Date
11/4/2023
Operation
Report Number
6
Report Start Date
11/8/2023
Report End Date
11/9/2023
Operation
RIG UP AND PT. RIH WITH GPT AND FOUND FLUID AT 4311'. POOH AND STANDBY WHILE FOX PUMPS N2 BUILDING TO
3450 PSI. RIH WITH GPT AND MONITOR FLUID LEVEL. FLUID WAS INITIALLY PUSHING AWAY AT 1.8 FPM / CHECKED HALF
AN HOUR LATER AND FLUID WAS PUSHING AWAY AT 1.2 FPM. LAST FLUID LEVEL AT 5104. POOH AND SWAP UNITS FROM
BIG TEX TO SNAP.
Report Number
7
Report Start Date
11/9/2023
Report End Date
11/10/2023
Operation
RIG UP WHILE FOX PUMPS WELL UP TO 3500. RIH WITH GPT AND FOUND FLUID BELOW PLUG DEPTH. POOH. MU AND RIH
WITH 3.71" CIBP, CORRELATE AND SET AT 6164', 50' ABOVE TOP PERFS. MAKE 2 RUNS OF 30' X 3" BAILER FULL, DUMPING
35' OF CEMENT ON TOP OF PLUG. POOH. MU GUN #4 FOR THE MORNING / RIG DOWN
Report Number
8
Report Start Date
11/10/2023
Report End Date
11/11/2023
API: 5028320192 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:Permit to Drill (PTD) #:223069
Page 2/3
Well Name: BRU 213-26
Report Printed: 12/5/2023www.peloton.com
Well Operations Summary
Operation
SAFETY MEETING / PTW
DRIVE TO H PAD AND FIRE UP AND SHOVEL OFF EQUIPMENT
DRIVE TO D PAD WHILE EQUIPMENT WARMS UP TO DROP OFF CEMENT STRING PACK ON H PAD / RIG UP AND BLEED WELL TO JUST OVER 1500 PSI
VERIFY GUNS 4 AND 5 / SURFACE CHECKS
STAB ON / MU FOR PT
RIH GUNS 1 & 2 (2EH -CCL-TS #1 = 17.0', 3BH - CCL-TS #2 = 11.8')
VERIFY SWITCHES / SWITCHES VERIFY
CONTINUE DOWNHOLE
CORRELATE (GUN4/PASS3)
LOG SENT TO TOWN
SPOT ON DEPTH (CCL DEPTH) (GUN4/PASS6)
SHOOT / PULL INTO POSITION GUN 5 (5868.2) (PRE-1511, 5-1550, 10-1579, 15-1599) SHOOT GUN 5 / POOH (PRE-1616, 5-1634, 10-1642, 15-1650)
OOH / MU GUN #6 (15' X 2 3/4”) DECISION MADE TO FLOW WELL
STAB ON AND STANDBY WHILE BRODUCTION TRIES TO FLOW WELL TOOK WELL DOWN TO 1408, NO LEL
RIH GUN #6 (CCL-TS=15.1')
SPOT ON DEPTH (CCL DEPTH) (PRE-1575, 5-1583, 10-1579, 15-1576)
SHOT / POOH (GUN6/PASS4)
OOH / MU GUNS 7 AND 8 (2 3/4" X 8' AND 10’) SWITCHED
RIH GUN 7 AND 8 (CCL-TS #7=22' / CCL-TS #8= 9')
PULL INTO POSITION GUN 7 (GUN7-8/PASS7) (PRE-1565, 5-1557, 10-1535, 15-1510) SHOOT / PULL INTO POSITION GUN 8 (5794)
SHOT GUN 8 / POOH (PRE-1510, 1490, 10-1460, 15-1447)
OOH / MU GUN #9 (2 3/4" X 6’) CCL-TS=17.1'
RIH GUN #9
SPOT ON DEPTH (CCL DEPTH) (GUN9/PASS3)
SHOT / POOH (PRE-1356, 5-1359, 10-1359, 15-1359) OOH / MU GUN #10 (4' X 2 3/4")
RIH GUN #10 (CCL-TS=17.3)
SPOT ON DEPTH (CCL DEPTH) (GUN 10/PASS2)
SHOT / POOH (PRE-1355, 5-1355, 10-1353, 15-1352) OOH / RIG DOWN FOR THE NIGHT
BUILD SWITCH GUNS FOR TOMORROW
LEAVE H PAD
Report Number
9
Report Start Date
11/10/2023
Report End Date
11/11/2023
Operation
Report Number
10
Report Start Date
11/11/2023
Report End Date
11/12/2023
Operation
PJSM, DISCUSS DAILY OPERATIONS
DRIVE TO H PAD AND FIRE UP EQUIPMENT
DRIVE TO D PAD AND GATHER SUPPLIES
RIG UP
MU GUN #11 (8' X 2 3/4") CCL-TS=10.2'
STAB ON / MU FOR PT
RIH GUN #11
PULL NEW CORRELATION PASS (5700-4600)
LOG SENT TO TOWN (GUN11/PASS5)
LOG SHIFTED UPHOLE 1' AND RE-SENT
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN11/PASS7)
OOH / MU GUN #12 (10' X 2 3/4") CCL-TS=17.3
RIH GUN #12 (1214 OPENING)
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN12/PASS3)
OOH / GRAB LUNCH AT CAMP
MU GUN #13 (6' X 2 3/4")
RIH GUN #13 (CCL-TS=17.2)
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN13/PASS5)
OOH / DECISION MADE TO SHOOT A PEA SHOOTER / DRIVE TO CONNEX AND BUILD
2" X 2' PEA SHOOTER BUILT / CHECK FIRE / ARM GUN
RIH 2' PUNCHER (OPENING - 1102)
SPOT ON DEPTH AND START PUMPING N2
SHOT / POOH (PEA SHOOTER/PASS4) (1454, 1347, 1288, 1244)
RIH GUN #14 (23' X 2 3/4") CCL-TS=12.1'
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN14/PASS4)
OOH /RIG DOWN FOR THE NIGHT
LEAVE LOCATION
Report Number
11
Report Start Date
11/12/2023
Report End Date
11/13/2023
API: 5028320192 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:
Page 3/3
Well Name: BRU 213-26
Report Printed: 12/5/2023www.peloton.com
Well Operations Summary
Operation
PJSM, DISCUSS DAILY OPERATIONS, DRIVE TO H PAD / FIRE UP / WARM UP EQUIPMENT, PULL WIRE AND REHEAD / START RIG UP / TOP OFF FUEL,
MU GPT AND WB'S / SURFACE CHECKS, STAB ON / MU FOR PT, GOOD PT / RIH GPT4, LOG ACROSS PERFS (GPT4/PASS3) FLUID LEVEL IN SUMP
6100', SEND LOG TO TOWN, PRODUCTION ARRIVED ON LOCATION / SLOW BLEED TO 500, FOUND LEL AT 730 PSI / FLOW TO TANK / LOG GPT, FLUID
SAME SPOT 6100' DRY AND STABLE, PULL UPTO 4800 / POOH, OOH / GET WELL ONLINE AND LET IT FLOW, RIH GUNS 15 & 16, SPOT ON DEPTH GUN
#15 (3' X 2 3/4") CCL-TS=19.3' (GUN 15&16 PASS5), SHOT / PULL INTO POSITION GUN 16 (5194.2) (711, 731,799, 817), SHOT / POOH (827, 820, 817,
812), OOH / MU GUNS 17, 18 AND 19, RIH GUNS 17 18 AND 19 (3', 5', 2' X 2 3/4"), SPOT ON DEPTH GUN #17 (CCL -TS=22.3'), SHOT / PULL INTO
POSITION GUN #18 5136.9 (GUN 17-18-19/PASS2) (801, 802, 802, 798,SHOT GUN #18 / PULL INTO POSITION GUN #19 (5101.9), SHOT GUN #19 /
POOH, RIG DOWN & SECURE WELL. FLOW OVERNIGHT.
Report Number
12
Report Start Date
11/13/2023
Report End Date
11/14/2023
Operation
PJSM, DISCUSS DAILY OPERATIONS
TRAVEL TO LOCATION, FIRE UP EQUIPMENT / SHOVEL OFF WORK AREA. RIG UP,
SURFACE CHECKS / CHECK FIRE / MU GUNS 20, 21, AND 22 (2 3/4" X 3' 3' 5')
STAB ON / MU FOR PT
RIH GUNS 20, 21, AND 22 (CCL-TS'S= 26.3', 19.1', 9.9')
CORRELATE (GUNS20-21-22/PASS3)
LOG SENT TO TOWN
SPOT ON DEPTH (CCL DEPTH) GUN 20 (794, 794, 794,) POTENTIAL MISFIRE (GUNS20-21-22/PASS5)
SHOOT GUN 20 / SPOT ON DEPTH GUN 21 (5042.9)
SHOOT GUN #21 / SPOT ON DEPTH GUN #22 (5001.1)
SHOOT GUN #22 / POOH
OOH / BOTTOM GUN MISFIRE / INFORM TOWN / TROUBLESHOOT
PINCHED DETONATOR WIRE GROUNDED SHORTED OUT / SWITH WAS BURNT UP / WON'T READ
RIH GUN #20 (2 3/4" X 3') CCL-TS=15.3'
SPOT ON DEPTH (CCL DEPTH) (795,
SHOT / POOH (GUNS20/PASS1)
OOH / MU GUNS 23-24-25 (4' - 4' - 6' X 2 3/4")
RIH GUNS 23-24-25
SPOT ON DEPTH (CCL DEPTH) GUN 23 (GUNS23-24-25/PASS1)
SHOT / PULL INTO POSITION GUN 24 (4964.9)
SHOT / PULL INTO POSITION GUN 25 (4851.0
SHOT GUN 25 / POOH
OOH / MU GUNS 26 AND 27 (2 3/4" X 8'-14')
RIH GUNS 26 AND 27 (CCL-TS'S=26.3' AND 9')
SPOT ON DEPTH GUN 26
SHOT / PULL INTO POSITION GUN 27 (4767.0) (GUNS26-27/PASS2)
SHOT / POOH (GUNS26-27/PASS2) (884, 861, 852)
OOH / MU GUNS 28 AND 29
RIH GUNS 28 AND 29 (OPENING 847)
CORRELATE FOR LAST 2 GUNS (GUNS28-29/PASS2)
SPOT ON DEPTH (CCL DEPTH)
SHOT / PULL INTO POSITION GUN 29 (4700.1
SHOT / POOH (GUN28-29/PASS6)
OOH / FULL RIG DOWN
Report Number
13
Report Start Date
11/18/2023
Report End Date
11/19/2023
Operation
API: 5028320192 Field: Beluga River
Sundry #:
State: Alaska
Rig/Service:
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Cable Length:.
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:
Dated:.Sent Log to:
Pressure Test Lubicator:
GEO Gram Wt:15 Phasing:60 DEG Shot per ft.:6 Total Shots:156
1450 . .Final Pressure ...
Time Depth
6:00
7:00
7:45
8:05
10:15
11:00
10:45
12:17
12:35
12:50
13:30
14:04
14:28
14:54 6751.7
14:55 6763-6772
15:35
15:45
16:21 6491.5
16:23 6502-6512
16:58
15:09
15:41 6203.5
15:43 6214-6224
18:15
12:15 Elapsed Time 18:15 6:00 12.25 61.3
3 Run(s)
Total Crew Hours:
$0.00Daily Cost:
Logs Correlated To:
2 3/4"
4 1/2" 12.6# L-80
CBL ANCHORAGE
250Low Pressure:High Pressure:2500
PTW / SAFETY MEETING
SHOT / POOH (GUN2PASS3)
Unit #:
Fluid Level: NA Tag Depth: NA
Summary of Work:
HMX
Casing Size & Wt.:7 5/8" 29.7# L-80
Perforating Charges Mfg:
HMX or RDX:
Big Tex
Daily Summary
Operations Log
Job Parameters
Operation Entry
Initial Tbg / IA / OA Pressure:
WSR Data
11/5/2023
PERFORATE
GRANT LEVI
Hilcorp Alaska, LLC
Beluga River Unit
5
Personnel/Equipment
BRIAN WOOLEY
0
OOH / RIG DOWN FOR THE NIGHT
.
VICTOR SEE
BROOKLYN SMITH
.
.
OOH / MU GUN #3
RIH GUN #3 (10' X 2 3/4") CCL-TS=10.5'
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN3/PASS3)
SPOT ON DEPTH (CCL DEPTH)
Tubing Size & Wt.:
RIG UP WHILE STANDING BY ON CREW MEMBER AND TOOLS. MU TOOLSTRING AND RIH WITH GUN #1. PULL 1000 FT
LONG CORRELATION FROM 6900-5900 AND SEND TO TOWN. SHIFT LOG UPHOLE 1' AND RESEND. GOT THE GO AHEAD TO
USE LOG FOR FIRST 3 GUNS OF PHASE 1. SPOT ON DEPTH AND PERFORATE FROM 6763-6772. POOH. MU GUN # 2 AND
RIH, CORRELATE, SPOT ON DEPTH AND PERFORATE AND 6502-6512. POOH. MU GUN #3 AND RIH, CORRELATE, SPOT ON
DEPTH AND PERFORATE FROM 6214-6224. POOH AND TURN WELL OVER TO PRODUCTION. RIG DOWN FOR THE NIGHT.
Gun O.D. Size:
DRIVE TO TMC AND PICK UP TOW BEHIND
SPOT EQUIPMENT
START RIG UP
CHOPPER ARRIVED WITH CREW AND TOOLS / DROP OFF GEAR AT COTTONWOOD
CONTINIUE RIG UP
MU TOOLSTRING / SURFACE CHECKS
STAB ON / MU FOR PT
GOT TO 200 PSI AND TREE FLANGE STARTED LEAKING / STANDBY ON PRODUCTION
E-LINE CREW HAMMERING UP FLANGE
GOOD PT / RIH GUN #1 (2 3/4" X 9') CCL-TS=11.3'
RIH GUN #2 (10' X 2 3/4") CCL-TS=10.5'
CORRELATE (GUN1/PASS4)
LOG SENT TO TOWN (shift uphole 1')
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN1/PASS7) (TO SURF (GUN1/PASS8))
OOH / MU GUN #2
Big Tex
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/5/2023 Sent Log to:
Pressure Test Lubicator:
...Final Pressure ...
Time Depth
6:00
6:30
7:00
7:15
7:45
8:35
8:53
9:32
10:10
10:13
10:30
11:01
11:09
11:33
12:04
12:47
12:50
13:27
13:52
15:26
16:30
10:30 Elapsed Time 16:30 6:00 10.5 52.5
1 Runs
0
WSR Data
11/6/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Fluid Level: Tag Depth: NA
Personnel/Equipment
5 BRIAN WOOLEY
GRANT LEVI Unit #:Big Tex
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
Suspended Column
Summary of Work:
RIG UP AND PT. RIH WITH GPT AND MAKE MULTIPLE RUNS UP AND DOWNHOLE FIRST WHILE STATIC AND WHILE
BLEEDING WELL DOWN. 500 FT SUSPENDED COLUMN OF FLUID DOWNHOLE. DECISION MADE TO PRESSURE UP WELL
WITH N2 AND SET CIBP. N2 NOT AVAILABLE SO RIGGED DOWN AND GOT EVERYTHING READY FOR CIBP AND CEMENT.
DROVE TO DW-1 PAD AND GOT CROSSOVER OFF OF BRU 232-09.
Job Parameters
Logs Correlated To:Gun 1 Correlation Pass Anchorage
Low Pressure:250 High Pressure:2500
ON LOCATION / RIG UP AND MU FOR GPT RUN
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
Operation Entry
SAFETY MEETING
PTW
FIRE UP EQUIPMENT ON H PAD
HEAD TO D PAD TO LOAD UP TOOLS FOR CIBP
STANDBY ON WORD FROM TOWN
STAB ON / MU FOR PT
GOOD PT / RIH GPT1
LOG FLUID LEVEL PASS
SEND LOG TO TOWN (BOTTOM ZONES SUSPENDING A COLUMN OF FLUID)
POOH
BUMP UP / DECISION MADE TO RUN MORE PASSES / RBIH GPT
MAKE UP / DOWN PASSES WHILE DROPPING WELL TO 500 PSI
BLEEDING DOWN (FLUID 6070-5600)
LOG UP FROM 6821 ( FLUID AT 6370)
SHuT IN AND LOG ACROSS PERFS (557-575 PSI) (GPT1/PASS10)
SUSPENDED FLUID COLUMN / LOG SENT TO TOWN
Total Crew Hours:
Daily Cost: $0.00
POOH
OOH / STANDBY IN LUBRICATOR ON WORD
STAB OFF AND RIG DOWN / CLEAN UP JOB SIGHT / GO TO D PAD AND GET TOOLS FOR CEMENT
DRIVE TO DW-1 PAD AND GET CROSSOVER OFF OF BRU 232-09
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/5/2023 Sent Log to:
Pressure Test Lubicator:
NA Gram Wt:
NA Phasing:NA Shot per ft.: NA Total Shots: NA
1500 . .Final Pressure ...
Time Depth
6:00
6:30
6:47
7:00
7:50
8:03
8:43
9:38
10:05
12:41
13:07
13:25
13:40
14:14
14:51
15:18
15:53
19:00
13:00 Elapsed Time 19:00 6:00 13 65.0
1 Runs
UNITS SWAPPED OVER / DONE FOR THE NIGHT
Total Crew Hours:
Daily Cost: $8,557.50
OOH / RIG DOWN / SWAP UNITS
GOOD PT / RIH GPT / 3 WB'S
PULL FLUID LEVEL PASS (GPT2/PASS2)
PUT LOG TOGETHER AND SEND TO TOWN (SUSPENDED FLUID FROM 6375-4311)
OOH / STANDBY WHILE FOX PUMPS N2
FOX BUILT PRESSURE TO 3400 NO BREAKOVER / OUT OF N2
GREASE LOCKED IN TUBES / KILL GREASE / ATTEMPT TO FALL / BLEED DOWN / GET SL WB'S
STAB OFF / MU 2 SL WB'S
STAB ON / RIH GPT
FLUID LEVEL 5001' / STANDBY FOR :30 AND CHECK AGAIN
FLUID LEVEL 5070 / PUSHING AT 1.8 FPM
FLUID LEVEL 5104 / PISHING AT / 1.26 FPM / POOH
STAB ON / MU FOR PT
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
Operation Entry
SAFETY MEETING
PTW
DRIVE TO LOCATION / FIRE UP EQUIPMENT
RIG UP
Gun O.D. Size:NA HMX or RDX:NA
Summary of Work:
RIG UP AND PT. RIH WITH GPT AND FOUND FLUID AT 4311'. POOH AND STANDBY WHILE FOX PUMPS N2 BUILDING TO
3450 PSI. RIH WITH GPT AND MONITOR FLUID LEVEL. FLUID WAS INITIALLY PUSHING AWAY AT 1.8 FPM / CHECKED HALF
AN HOUR LATER AND FLUID WAS PUSHING AWAY AT 1.2 FPM. LAST FLUID LEVEL AT 5104. POOH AND SWAP UNITS FROM
BIG TEX TO SNAP.
Job Parameters
Logs Correlated To:GUN 1 CORRELATION PASS ANCHORAGE
Low Pressure:250 High Pressure:2500
Perforating Charges Mfg:
Fluid Level: 5104 Tag Depth: NA
Personnel/Equipment
5 BRIAN WOOLEY
GRANT LEVI Unit #:Big Tex
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
0
WSR Data
11/8/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/5/2023 Sent Log to:
Pressure Test Lubicator:
3500 . .Final Pressure 17 . .
Time Depth
6:00
6:30
6:45
7:00
8:30
9:00
9:30
10:23 6645
10:30
11:13
11:45
12:26
12:35 6149.5
12:37 6164
12:42
13:30
14:00
15:11
15:35
16:20
16:40
17:00
17:48
11:48 Elapsed Time 17:48 6:00 11.8 59.0
4 Runs
DUMP CEMENT / POOH
OOH / RIG DOWN FOR THE NIGHT
RIH CEMENT (10 GALLONS / 17 PPG)
DUMP CEMENT / POOH
OOH / FILL BAILER FOR RUN 2 (10 GALLONS / 17 PPG)
RIH CEMENT #2
Total Crew Hours:
Daily Cost: $0.00
WELL BLEED TO 1750 / CHECK FIRE AND FILL BAILER
STAB ON / MU FOR PT
GOOD PT / RIH GPT WITH WB'S
FLUID LEVEL (GPT3/PASS4)
POOH
OOH / MU TOOLSTRING FOR PLUG / CHECK FIRE /
RIH 3.71" CIBP (CCL-TOP OF PLUG=14.5') (STOP AT 6190 CCL TO STAY OUT OF PERFS)
PULL CIBP CORRELATION PASS (CIBP/PASS3)
SPOT ON DEPTH (CCL DEPTH)
SET (SLOW SET CHARGE) (CIBP/PASS5)
POOH
OOH / BLEED DOWN / MIX CEMENT
SURFACE CHECKS / POWER UP GPT
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
Operation Entry
SAFETY MEETING
PTW
FOX START PUMPING N2 BRINGING WELL BACK UP TO 3500 PSI
RIG UP / IRON OUT A FEW KINKS WITH NEW UNIT
Summary of Work:
RIG UP WHILE FOX PUMPS WELL UP TO 3500. RIH WITH GPT AND FOUND FLUID BELOW PLUG DEPTH. POOH. MU AND RIH
WITH 3.71" CIBP, CORRELATE AND SET AT 6164, 50' ABOVE TOP PERFS. MAKE 2 RUNS OF 30' X 3" BAILER FULL, DUMPING
35' OF CEMENT ON TOP OF PLUG. POOH. MU GUN #4 FOR THE MORNING / RIG DOWN
Job Parameters
Logs Correlated To:GUN 1 PERF CORRELATION PASS NA
Low Pressure:250 High Pressure:2500
Fluid Level: 6645 Tag Depth: NA
Personnel/Equipment
5 BRIAN WOOLEY
GRANT LEVI Unit #:Big Tex
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
0
WSR Data
11/9/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/5/2023 Sent Log to:
Pressure Test Lubicator:
GEO Gram Wt:15 Phasing:60 DEG Shot per ft.: 6 Total Shots: 330
1512 . .Final Pressure 1352 . .
Time Depth
6:00
6:45
7:15
7:35
8:00
8:15
8:40
8:45 200
8:47
9:09
9:25
10:10 5892
10:11 5909-5918
10:32 5880-5883
11:06
11:15
11:47
11:50
12:16 5814.9
12:17 5830-5845
12:52
13:13
13:46 5797
13:48 5819-5827
14:00 5803-5813
14:32
14:55
15:15
15:17
15:50
16:07
16:27 5638.7
16:33 5656-5660
17:05
17:30
20:00
14:00 Elapsed Time 20:00 6:00 14 70.0
7 Runs
RIH GUN #9
SPOT ON DEPTH (CCL DEPTH) (GUN9/PASS3)
SHOT / POOH (PRE-1356, 5-1359, 10-1359, 15-1359)
OOH / MU GUN #10 (4' X 2 3/4")
RIH GUN #10 (CCL-TS=17.3)
SPOT ON DEPTH (CCL DEPTH) (GUN 10/PASS2)
OOH / MU GUNS 7 AND 8 (2 3/4" X 8' AND 10') SWITCHED
RIH GUN 7 AND 8 (CCL-TS #7=22' / CCL-TS #8= 9')
PULL INTO POSITION GUN 7 (GUN7-8/PASS7) (PRE-1565, 5-1557, 10-1535, 15-1510)
SHOOT / PULL INTO POSITION GUN 8 (5794)
SHOT GUN 8 / POOH (PRE-1510, 1490, 10-1460, 15-1447)
OOH / MU GUN #9 (2 3/4" X 6') CCL-TS=17.1'
RIH GUNS 1 & 2 ( 2EH -CCL-TS #1 = 17.0', 3BH - CCL-TS #2 = 11.8')
VERIFY SWITCHES / SWITCHES VERIFY
CONTINUE DOWNHOLE
CORRELATE (GUN4/PASS3)
LOG SENT TO TOWN
SPOT ON DEPTH (CCL DEPTH) (GUN4/PASS6)
SHOOT / PULL INTO POSITION GUN 5 (5868.2) (PRE-1511, 5-1550, 10-1579, 15-1599)
SHOOT GUN 5 / POOH (PRE-1616, 5-1634, 10-1642, 15-1650)
OOH / MU GUN #6 (15' X 2 3/4") DECISION MADE TO FLOW WELL
Total Crew Hours:
Daily Cost: $0.00
STAB ON / MU FOR PT
SHOT / POOH (GUN6/PASS4)
SHOT / POOH (PRE-1355, 5-1355, 10-1353, 15-1352)
OOH / RIG DOWN FOR THE NIGHT
BUILD SWITCH GUNS FOR TOMORROW
LEAVE H PAD
STAB ON AND STANDBY WHILE BRODUCTION TRIES TO FLOW WELL
TOOK WELL DOWN TO 1408, NO LEL
RIH GUN #6 (CCL-TS=15.1')
SPOT ON DEPTH (CCL DEPTH) (PRE-1575, 5-1583, 10-
Operation Entry
SAFETY MEETING / PTW
DRIVE TO H PAD AND FIRE UP AND SHOVEL OFF EQUIPMENT
DRIVE TO D PAD WHILE EQUIPMENT WARMS UP TO DROP OFF CEMENT STRING
PACK ON H PAD / RIG UP AND BLEED WELL TO JUST OVER 1500 PSI
VERIFY GUNS 4 AND 5 / SURFACE CHECKS
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
LOW PRESSURE:250 High Pressure:2500
Perforating Charges Mfg:
Gun O.D. Size:2 3/4"HMX or RDX:HMX
Summary of Work:
RIG UP AND PT. RIH AND CORRELATE. SHOT A TOTAL OF 7 GUNS FROM: 5909-5918, 5880-5883, 5830-5845, 5819-5827, 5803-
5813, 5783-5789, AND 5656-5660. RIG DOWN FOR THE NIGHT AND BUILD STRIP GUNS FOR TOMORROW.
Job Parameters
Logs Correlated To:GUN 1 CORRELATION PASS ANCHORAGE
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
Fluid Level: NA Tag Depth: NA
Personnel/Equipment
5 Brandon Bauer
GRANT LEVI Unit #:Snap
WSR Data
11/10/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
0
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/10/2023 Sent Log to:
Pressure Test Lubicator:
GRO Gram Wt:
15 Phasing:60 DEG Shot per ft.: 6 Total Shots: 282
1328 . .Final Pressure 1109 . .
Time Depth
6:00
6:45
7:15
7:30
7:40
8:05
8:25
8:40
9:05
9:20
9:30
9:53 5601.8
9:55 5612-5620
10:27
10:40
11:11 5506.7
11:13 5524-5534
11:45
12:25
12:51
13:13 5495.8
13:17 5513-5519
13:51
14:45
15:05
15:36 5303.8
15:50 5327-5329
16:48
15:19 5303.9
15:25 5316-5339
17:55
18:30
12:30 Elapsed Time 18:30 6:00 12.5 0.0
5 Runs
OOH /RIG DOWN FOR THE NIGHT
2" X 2' PEA SHOOTER BUILT / CHECK FIRE / ARM GUN
RIH 2' PUNCHER (OPENING - 1102)
SPOT ON DEPTH AND START PUMPING N2
SHOT / POOH (PEA SHOOTER/PASS4) (1454, 1347, 1288, 1244)
Total Crew Hours:
Daily Cost: #REF!
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN11/PASS7)
OOH / MU GUN #12 (10' X 2 3/4") CCL-TS=17.3
RIH GUN #12 (1214 OPENING)
LEAVE LOCATION
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN13/PASS5)
OOH / DECISION MADE TO SHOOT A PEA SHOOTER / DRIVE TO CONNEX AND BUILD
RIH GUN #14 (23' X 2 3/4") CCL-TS=12.1'
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN12/PASS3)
OOH / GRAB LUNCH AT CAMP
MU GUN #13 (6' X 2 3/4")
RIH GUN #13 (CCL-TS=17.2)
SPOT ON DEPTH (CCL DEPTH)
SHOT / POOH (GUN14/PASS4)
LOG SHIFTED UPHOLE 1' AND RE-SENT
Operation Entry
SAFETY MEETING
PTW
DRIVE TO H PAD AND FIRE UP EQUIPMENT
DRIVE TO D PAD AND GATHER SUPPLIES
RIG UP
MU GUN #11 (8' X 2 3/4") CCL-TS=10.2'
STAB ON / MU FOR PT
RIH GUN #11
PULL NEW CORRELATION PASS (5700-4600)
LOG SENT TO TOWN (GUN11/PASS5)
Initial Tbg / IA / OA Pressure:
Low Pressure:250 High Pressure:2500
Perforating Charges Mfg:
Gun O.D. Size:2 3/4"HMX or RDX:HMX
Tubing Size & Wt.:41/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Summary of Work:
RIG UP AND PT. RIH AND PULL NEW CORRELATION. SHOT A TOTAL OF 4 GUNS PLUS A PEA SHOOTER FROM: 5612-5620,
5524-5534, 5513-5519, AND 5316-5339. POOH AND RIG DOWN.
Job Parameters
Logs Correlated To:CORRELATION PASS (GUN4/PASS3)ANCHORAGE
Fluid Level: NA Tag Depth: NA
Personnel/Equipment
0 Josh Stephenso n
#REF!Unit #:Big Tex
#REF!
#REF!
#REF!
#REF!
Daily Summary
#REF!
WSR Data
11/11/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/11/2023 Sent Log to:
Pressure Test Lubicator:
GEO Gram Wt:
15 Phasing:60 DEG Shot per ft.: 6 Total Shots: 108
966 . .Final Pressure 794 . .
Time Depth
6:00
6:45
7:15
7:51
8:20
8:51
9:30
10:00
10:29
10:50
11:16
11:31
12:06
16:00
16:40 5244.7
16:41 5264-5267
16:47 5204-5209
17:10
17:25
17:45 5142.7
17:47 5165-5168
18:01 5150-5155
18:19 5111-5113
18:51
19::00
12:51 Elapsed Time 18:51 6:00 12.85 64.3
3 Runs
LOG ACROSS PERFS (GPT4/PASS3) FLUID LEVEL IN SUMP 6100'
SEND LOG TO TOWN
PRODUCTION ARRIVED ON LOCATION / SLOW BLEED TO 500
FOUND LEL AT 730 PSI / FLOW TO TANK / LOG GPT
FLUID SAME SPOT 6100' DRY AND STABLE
PULL UPTO 4800 / POOH
OOH / GET WELL ONLINE AND LET IT FLOW
RIH GUNS 15 & 16
SPOT ON DEPTH GUN #15 (3' X 2 3/4") CCL-TS=19.3' (GUN15&16/PASS5)
Total Crew Hours:
Daily Cost: $18,371.50
GOOD PT / RIH GPT4
SPOT ON DEPTH GUN #17 (CCL -TS=22.3')
SHOT / PULL INTO POSITION GUN #18 5136.9 (GUN 17-18-19/PASS2) (801, 802, 802, 798,
SHOT GUN #18 / PULL INTO POSITION GUN #19 (5101.9)
SHOT GUN #19 / POOH
OOH / CLOSING PRESSURE DOWN TO 793 PSI
SHOT / PULL INTO POSITION GUN 16 (5194.2) (711, 731,799, 817)
SHOT / POOH (827, 820, 817, 812)
OOH / MU GUNS 17, 18 AND 19
RIH GUNS 17 18 AND 19 (3', 5', 2' X 2 3/4")
RIG DOWN FOR THE NIGHT
STAB ON / MU FOR PT
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
Operation Entry
SAFETY MEETING / PTW
DRIVE TO H PAD / FIRE UP / WARM UP EQUIPMENT
PULL WIRE AND REHEAD / START RIG UP / TOP OFF FUEL
MU GPT AND WB'S / SURFACE CHECKS
Gun O.D. Size:2 3/4"HMX or RDX:HMX
Summary of Work:
RIG UP AND PT. RIH WITH GPT AND FOUND FLUID LOW AT 6100'. START DRAWING WELL DOWN AND FOUND LEL AT 731
PSI. FLOW WELL AND STABALIZE AT 2.2 MCF AT 927 PSI. DECISION MADE TO CONTINUE PERFORATING. SHOT 5 MORE
GUNS FROM: 5264-5267, 5204-5209, 5165-5168, 5150-5155, AND 5111-5113. POOH AND RIG DOWN. CLOSING PRESSURE
DOWN TO 793 PSI.
Job Parameters
Logs Correlated To:CORRELATION (GUN11/PASS5)ANCHORAGE
Low Pressure:250 High Pressure:2500
Perforating Charges Mfg:
Fluid Level: 6100 Tag Depth: .
Personnel/Equipment
5 JOSHUA STEPHENSON
GRANT LEVI Unit #:SNAP
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
0
WSR Data
11/12/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
Dated:11/11/2023 Sent Log to:
Pressure Test Lubicator:
GEO Gram Wt:
15 Phasing:60 DEG Shot per ft.: 6 Total Shots: 64
794 . .Final Pressure 850 . .
Time Depth
6:15
6:45
7:10
7:45
8:15
8:25
8:39
9:03
9:19
9:39 5057.7
9:41 5084-5087
10:04 5062-5065
10:20 5011-5016
10:45
11:00
11:37
11:57 5068.7
11:59 5084-5087
12:31
12:51
13:31 4973.7
13:35 4999-5003
13:45 4983-4987
13:55 4860-4866
14:17
15:24 4804.7
15:32 4831-4839
15:45 4776-4790
16:37
16:39
17:03
17:41 4705.9
17:45 4731-4736
17:53 4711-4723
18:22
12:07 Elapsed Time 18:22 6:15 12.1167 60.6
5 Runs
0
WSR Data
11/13/2023
Hilcorp Alaska, LLC
Beluga River Unit PERFORATE
Fluid Level: 6100 Tag Depth: .
Personnel/Equipment
5 JOSHUA STEPHENSON
GRANT LEVI Unit #:SNAP
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
Gun O.D. Size:2 3/4"HMX or RDX:HMX
Summary of Work:
RIG UP AND PT. RIH AND PERFORATED A TOTAL OF 10 ZONES FROM: 5084-5087, 5062-5065, 5011-5016, 4999-5003, 4983-4987,
4860-4866, 4831-4839, 4776-4790, 4731-4736, AND 4711-4723 POOH AND RIG DOWN.
Job Parameters
Logs Correlated To:CORRELATION (GUN11/PASS5)ANCHORAGE
Low Pressure:250 High Pressure:2500
Perforating Charges Mfg:
SURFACE CHECKS / CHECK FIRE / MU GUNS 20, 21, AND 22 (2 3/4" X 3' 3' 5')
Tubing Size & Wt.:4 1/2" 12.6# L-80 Casing Size & Wt.:7 5/8" 29.7# L-80
Operations Log
Initial Tbg / IA / OA Pressure:
Operation Entry
SAFETY MEETING
PTW AT OFFICE
FIRE UP EQUIPMENT / SHOVEL OFF WORK AREA
RIG UP
SPOT ON DEPTH (CCL DEPTH) (795,
STAB ON / MU FOR PT
RIH GUNS 20, 21, AND 22 (CCL-TS'S= 26.3', 19.1', 9.9')
CORRELATE (GUNS20-21-22/PASS3)
LOG SENT TO TOWN
SPOT ON DEPTH (CCL DEPTH) GUN 20 (794, 794, 794,) POTENTIAL MISFIRE (GUNS20-21-22/PASS5)
SHOOT GUN 20 / SPOT ON DEPTH GUN 21 (5042.9)
SHOOT GUN #21 / SPOT ON DEPTH GUN #22 (5001.1)
SHOOT GUN #22 / POOH
OOH / BOTTOM GUN MISFIRE / INFORM TOWN / TROUBLESHOOT
PINCHED DETONATOR WIRE GROUNDED SHORTED OUT / SWITH WAS BURNT UP / WON'T READ
RIH GUN #20 (2 3/4" X 3') CCL-TS=15.3'
SHOT / POOH (GUNS20/PASS1)
OOH / MU GUNS 23-24-25 (4' - 4' - 6' X 2 3/4")
RIH GUNS 23-24-25
OOH / FULL RIG DOWN
SPOT ON DEPTH (CCL DEPTH) GUN 23 (GUNS23-24-25/PASS1)
SHOT / PULL INTO POSITION GUN 24 (4964.9)
SHOT / PULL INTO POSITION GUN 25 (4851.0
SHOT GUN 25 / POOH
OOH / MU GUNS 28 AND 29
RIH GUNS 28 AND 29 (OPENING 847)
CORRELATE FOR LAST 2 GUNS (GUNS28-29/PASS2)
SPOT ON DEPTH (CCL DEPTH)
SHOT / PULL INTO POSITION GUN 29 (4700.1
SHOT / POOH (GUN28-29/PASS6)
Total Crew Hours:
Daily Cost: $34,229.50
OOH / MU GUNS 26 AND 27 (2 3/4" X 8'-14')
RIH GUNS 26 AND 27 (CCL-TS'S=26.3' AND 9')
SPOT ON DEPTH GUN 26
SHOT / PULL INTO POSITION GUN 27 (4767.0) (GUNS26-27/PASS2)
SHOT / POOH (GUNS26-27/PASS2) (884, 861, 852)
Alaska E-Line Services Well Service Report
Client:Ticket Number: 4562
Field:Scope of Work:
Well No:BRU 213-26 Wellhead Connection:4 1/2" OTIS AFE # / PO #
Service Personnel: Company Rep.:
(Lead Operator)
(Assistant Operator)Engine hours on Arrival:.
(Assistant Operator)Engine Hours on Departure:.
(Assistant Operator)Tool(s) S/N:.
(Assistant Operator)
...Final Pressure .. . .
Time Depth
6:15
7:30
8:30
9:00
9:30
10:00
10:30
12:00
12:30
14:00
14:45
13:30
16:00
16:30
17:00
10:45 Elapsed Time 17:00 6:15 10.75 53.8
0 Runs
Total Crew Hours:
Daily Cost: $0.00
AT IVAN / MEASURE AND SPOT CRANE / SPOT UNIT / SPOT HEATER / SPOT LIGHT PLANT
UNLOAD GUNS AND CROSSOVER / OPEN SWAB AND MASTER TO CHECK PRESSURE - 1280 PSI
FOUND THAT TREE FLANGE WAS LEAKING / CLOSE SWAB AND MASTER AGAIN / BLEED DOWN
DEPART IVAN FOR CAMP
STOP AT CONNEX AND GET GEAR WHICH WAS LOADED FOR FLIGHT AND DRIVE BACK TO CAMP
DRIVE BACK TO H PAD / FILL HEATER WITH DIESEL AND STAGE BY UNITS
DRIVE CRANE OVER TO D PAD / BORROW ZOOM BOOM AND SWAP OUT GREASE DRUMS
PICK UP SLOBBER LINE FROM MECHANIC SHOP AND BLOW IT OUT / PUT BACK ON CRANE
BREAK FOR LUNCH / GET UPDATES THAT CHOPPER MIGHT FLY OR DO A TEST FLIGHT
CHOPPER IN AIR DOING TEST FLIGHT / STANDING BY ON WORD
DECISION MADE TO DRIVE TO IVAN RIVER AND SPOT EQUIPMENT
Operation Entry
SAFETY MEETING / PTW
DRIVE TO H PAD AND FIRE UP EQUIPMENT / CLEAN UP UNITS / BUILD PEASHOOTER / FIRING HEAD
DRIVE UNITS TO FUEL UP AND STAGE NEXT TO MECHANICS SHOP
DRIVE TO D PAD AND GET TOOLS THAT ARE FLYING BACK TO OSK WITH US
CLEAN AND STICKER EQUIPMENT GOING IN AND STAGE IN CONNEX
Operations Log
Initial Tbg / IA / OA Pressure:
Summary of Work:
SAFETY MEETING. SCHEDULED FLIGHT AT 10:00 BUT WEATHER WAS QUESTIONABLE SO GOT EVERYTHING STAGED AND
READY TO GO TO IVAN 41-01. FILLED UNITS / BUILT PEA SHOOTER AND FIRING HEAD / LOADED GUNS AND DETOS INTO
UNIT. FLIGHT WAS DELAYED SO FILLED HEATER AND STAGED / BORROWED ZOOM BOOM AND OFFLOADED/LOADED
MORE 220 GREASE ON CRANE. TOOK A BREAK FOR LUNCH. AFTER LUNCH PILOTS DID A TEST FLIGHT AND WE WERE
WAITING ON WORD WHEN DECISION WAS MADE TO DRIVE OUT TO IVAN AND SPOT EQUIPMENT. STOPPED BY K PAD ON
THE WAY OUT AND GOT 2 7/8" 8 ROUND CROSSOVER FROM SLICKLINE. SPOTED CRANE, UNIT, LIGHT PLANT, AND HEATER
ON PAD. DROVE BACK FROM IVAN TO OFFICE / SWAPPED OUT TRUCKS BECAUSE HEAT WAS OUT IN OURS / PICKED UP
BAGS FROM CONNEX AND DROVE BACK TO CAMP.
VICTOR SEE
BROOKLYN SMITH
.
.
Daily Summary
Fluid Level: na Tag Depth: na
Personnel/Equipment
5 JOSHUA STEPHENSON
GRANT LEVI Unit #:snap
WSR Data
11/14/2023
Hilcorp Alaska, LLC
Beluga River Unit MOBE UP FOR IRU 41-01
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AE A
A
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.10.09 14:01:52 -08'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.10.12 09:05:47 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
70
Yes X No X Yes 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 402 2.44
Type I II 173 1.16
4
22.09
Hanger 13 5/8 BTC 0.64 22.09 21.45
2,802.59 26.13
Pup jt. 7 5/8 29.7 L-80 BTC Tenaris 4.04 26.13
1.29 2,803.59 2,802.59
Casing 7 5/8 29.7 L-80 TXP BTC Tenaris 2,776.17
Float collar 8 5/8 BTC Innovex
Installed 35 centralizers on every other jt. up to 300'.
Casing 7 5/8 29.7 L-80 TXP BTC Tenaris 82.74 2,886.33 2,803.59
www.wellez.net WellEz Information Management LLC ver_04818br
4
Type of Shoe:Forum Casing Crew:Parker
12 175
2,888.102,895.00 2,802.30
CEMENTING REPORT
Csg Wt. On Slips:25,000
Spud mud
15:56 9/26/2023 Surface
15.8 34
Bump press
Visual
Bump Plug?
129/129
1408
74
HES
FI
R
S
T
S
T
A
G
E
10.5Tune 60
9.1 4.2
100
742
Csg Wt. On Hook:40,000 Type Float Collar:Innovex No. Hrs to Run:9.5
BTC Forum 1.77 2,888.10 2,886.33
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 213-26 Date Run 26-Sep-23
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
2,802.30
Floats Held
Spud mud
Rotate Csg Recip Csg Ft. Min. PPG9.1
Shoe @ 2888.1 FC @ Top of Liner
Casing (Or Liner) Detail
Shoe 8 5/8
TD Shoe Depth: PBTD:
Jts.
1
1
108
Yes X No Yes X No 30
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? Yes X No % Returns during job
Cement returns to surface? Yes X 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
Shoe 5
Rotate Csg Recip Csg Ft. Min. PPG9.65
Shoe @ 7196 FC @ Top of Liner 2692.957,152.95
Floats Held
6% KCL PHPA mud
CASING RECORD
County State Alaska Supv.J Murphy / J Richardson
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 213-26 Date Run 8-Oct-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC JHOBBS 1.81 7,196.00 7,194.19
Csg Wt. On Hook:44,000 Type Float Collar:JHOBBS No. Hrs to Run:13.5
9.65 3
75
1168
FI
R
S
T
S
T
A
G
E
10.5Tuned 30
101/104
1597
4
HES
15.3 19
Bump press
CBL
Bump Plug?
12:27 10/9/2023 2700'
7,196.007,200.00 7,112.19
CEMENTING REPORT
Csg Wt. On Slips:29,000
6% KCL PHPA
12 165
Type of Shoe:JHOBBS Casing Crew:Parker
Baker ZXP LTP
www.wellez.net WellEz Information Management LLC ver_04818br
3
Ran 53 Hydro form centralizers.
Liner 4 1/2 12.6 L-80 TXP/BTC Tenaris 41.55 7,194.19 7,154.45
Float collar 5 BTC JHOBBS 1.50 7,154.45 7,152.95
Liner 4 1/2 12.6 L-80 TXP/BTC Tenaris 39.66 7,152.95 7,113.29
Landing collar 5 BTC JHOBBS 1.10 7,113.29 7,112.19
Liner 4 1/2 12.6 L-80 TXP/BTC Tenaris 4,386.84 7,112.19 2,725.35
XO Pup 5 1/2 563 B x 4.5 Baker 1.01 2,725.35 2,724.34
Baker ZXP LTP hanger 6 5/8 TSH H563 31.44 2,724.34 2,692.90
Type I II 371 2.39
Type I II 99 1.24
3
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: BRU 213-26 AOGCC 10-403 2323-559 PTD 223-069 - CBL for approval
Date:Friday, October 20, 2023 9:09:00 AM
Attachments:image005.png
image006.png
image007.png
Jake,
Hilcorp has approval to proceed with perfs per sundry 323-559
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, October 20, 2023 8:14 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: BRU 213-26 AOGCC 10-403 2323-559 PTD 223-069 - CBL for approval
Hi Bryan,
Please see attached CBL for approval. We were fighting the file size, this one is much smaller. Below is a snapshot
of the WBD for reference.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, October 20, 2023 5:28 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] RE: BRU 213-26 AOGCC 10-403 2323-559 PTD 223-069 Approved 10-16-23
Jake,
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.
I couldn’t open the file attachment. Could you send it in .pdf and also provide some context for your email.
Thanks
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: Thursday, October 19, 2023 3:39 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 213-26 AOGCC 10-403 2323-559 PTD 223-069 Approved 10-16-23
Bryan,
Please see attached CBL and snapshot below.
Thanks,
Jake
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 namedabove. 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 ofthis 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 numberis 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 regardand the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy ofthis 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 numberis 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.
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 10/20/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 213-26
- PTD 223-069
- API 50-283-20192-00-00
FINAL MUDLOGS - EOW DRILLING REPORTS (09/23/2023 to 10/07/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINT FILES (2” and 5” MD and TVD COLOR 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: 223-069
T38093
10/24/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.10.24
10:20:28 -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: 10/18/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 213-26
- PTD 223-069
- API 50-283-20192-00-00
FINAL LWD FORMATION EVALUATION LOGS (09/23/2023 to 10/07/2023)
EWR-M5, AGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-069
T38082
10/20/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.10.20
11:24:54 -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):
7,200'N/A
Casing Collapse
Structural
Conductor
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 2,695' MD / 2,353' TVD; N/A
6,683'7,112'6,597'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 213-26CO 802
Same
6,679'4-12/"
~2216 psi
4,503'
N/A
Length
October 24, 2023
Tieback
7,196'
Perforation Depth MD (ft):
See Attached Schematic
6,890psi
120'120'
2,888'
Size
120'
2,888'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6 # / L-80
TVD Burst
2,695'
8,430psi
2,530'
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
FEDA029657
223-069
50-283-20192-00-00
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
O
66
t
2
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 8:56 am, Oct 11, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.10.10 16:22:00 -
08'00'
Noel Nocas
(4361)
CT BOP test to 2500 psi.
Submit CBL to AOGCC and obtain approval before perforating.
10-407
BJM 10/16/23
X
Perforate
DSR-10/13/23SFD 10/16/2023
* Beluga River, Strlg-Beluga Gas Pool - Prod. Code 92500 SFD
*
Yes, for CT work only 10/16/23
Bryan McLellan
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.10.16 21:24:44
-06'00'10/16/23
Well Prognosis
Well Name:BRU 213-26 API Number:50-283-20192-00-00
Current Status:Gas Producer Permit to Drill Number:223-069
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: 2868 psi @ 6834’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2216 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 213-26 is the fourth of five grass roots wells 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.
4. Clean out wellbore to PBTD, 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
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 4628’ 4195’
Bottom Sand Beluga J 7032’ 6520’
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 12.9 ppg EMW FIT at the surface casing shoe (0.671 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.671-0.1) = 2216 psi / 0.571 = 3880‘ TVD
10. RDMO
11. Turn well over to production & flow test well
Shallowest Allowable Perf TVD == 3880‘ TVD
Perforate and test Beluga sands w
Well Prognosis
Contingencies:
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 DMA 10-10-23
CURRENT SCHEMATIC
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112’ MD / 6,597’ TVD
TD = 7,200’ MD / 6,683’ TVD
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 2,888’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,693’ 7,196’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,698’
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
1 2,695’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2” Pumped 165 bbl 12# lead, 99 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
6-3/4”
hole
2
1
Updated by DMA 10-10-23
PROPOSED
Beluga River Unit
BRU 213-26
PTD: 50-283-20192-00-00
API: 223-069
PBTD = 7,112’ MD / 6,597’ TVD
TD = 7,200’ MD / 6,683’ TVD
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 2,888’
4-1/2" Prod Lnr 12.6 L-80 TXP 3.958” 2,693’ 7,196’
4-1/2" Prod Tieback 12.6 L-80 TXP 3.958” Surf 2,698’
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
1 2,695’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
6-3/4”
hole
2
1
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel F-J ±4,628’ ±7.-32’ ±4,195’ ±6,520’ Proposed TBD
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 175 bbls 12# lead, 34 bbls 15.8# tail, recover 74bbls lead to pits. TOC @
Surface.
4-1/2” Pumped 165 bbl 12# lead, 20 bbls 15.3# tail. Circulate 4bbls off liner top to surface.
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.
1
Regg, James B (OGC)
From:Jay Murphy - (C) <Jay.Murphy@hilcorp.com>
Sent:Tuesday, October 10, 2023 1:21 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT BRU 213-26 10-10-2023
Attachments:MIT BRU 213-26 10-10-2023.xlsx; MIT BRU 213-26 10-10-23 Chart.pdf
Thank You and Best Regards,
Jay Murphy/ DSM
Hilcorp Alaska, LLC
HAK Rig 147
Office: 907‐776‐6776
Cell: 907‐715‐9211
Jay.Murphy@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 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 213-26PTD 2230690
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230690 Type Inj N Tubing 0 3650 3650 3650 Type Test P
Packer TVD 2365 BBL Pump 1.4 IA 0 90 90 90 Interval O
Test psi 3500 BBL Return 1.3 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230690 Type Inj N Tubing 0 200 200 200 Type Test P
Packer TVD 2365 BBL Pump 0.9 IA 0 2625 2625 2625 Interval O
Test psi 2500 BBL Return 0.9 OA 0 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:Post completion MIT-IA per PTD.
Notes:
Notes:
Hilcorp Alaska LLC
Beluga River Unit/ 213-26/ H Pad
Witness Waived
Jay Murphy
10/10/23
Notes:Post completion MIT-T per PTD.
Notes:
Notes:
Notes:
BRU 213-26
BRU 213-26
Form 10-426 (Revised 01/2017)2023-1010_MITP_BRU_213-26_2tests
jbr
J. Regg; 12/13/2023
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:Re: BRU 213-26 FIT (PTD 223-069)
Date:Thursday, September 28, 2023 6:43:10 PM
Attachments:image001.png
image002.png
Sean, Hilcorp has approval to proceed with the plan you’ve outlined below, with the
conditions
1. that if you see tight hole conditions above 5000 ft, you will continue pumping out of hole.
2. Set a trip speed limit to limit swab potential whenever pulling out without pumping,
regardless of bit depth.
Regards
Bryan
Sent from my iPhone
On Sep 28, 2023, at 6:36 PM, Sean McLaughlin
<Sean.Mclaughlin@hilcorp.com> wrote:
sean
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 213-26
JBR 11/21/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
Used 4-1/2" TJ, Manual choke valve failed on low grease and cycle passed. Accumulator bottles 15 @ 1000 psi
Test Results
TEST DATA
Rig Rep:Ken PoterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson
Rig Owner/Rig No.:Hilcorp 147 PTD#:2230690 DATE:9/27/2023
Type Operation:DRILL Annular:
250/3500Type Test:INIT
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopKPS230928124301
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5
MASP:
2420
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
13 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"P
#1 Rams 1 2-7/8" x 5" vb P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8" x 5" vb P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"FP
HCR Valves 2 3-1/8" & 2-1/P
Kill Line Valves 2 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1800
200 PSI Attained P15
Full Pressure Attained P84
Blind Switch Covers:Yall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4 @ 2700
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P16
#1 Rams P4
#2 Rams P4
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
99
9
9
9 9999
9
9
FP
Manual choke valve failed
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, Sterling -Beluga Gas Pool, BRU 213-26
Hilcorp Alaska, LLC
Permit to Drill Number: 223-069
Surface Location: 887’ FSL, 757’ FWL, Sec 26, T13N, R10W, SM, AK
Bottomhole Location: 2530' FSL, 189' FEL, Sec 27, 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 September 2023. 7
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.09.07 15:46:46
-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: 7,585' TVD: 7,045'
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): 98.2 15. Distance to Nearest Well Open
Surface: x- 318697 y- 2626036 Zone-4 79.7 to Same Pool: 1098' to BRU 244-27
16. Deviated wells: Kickoff depth: 269 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 40 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 2,895' Surface Surface 2,895' 2,533'
6-3/4" 4-1/2" 12.6# L-80 TXP 4,889' 2,695' 2,349' 7,585' 7,045'
Tieback 4-1/2" 12.6# L-80 TXP 2,695' Surface Surface 2,695' 2,349'
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
9/15/2023
4035' 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 - 964 ft3 / T 182 ft3
Effect. Depth MD (ft): Effect. Depth TVD (ft):
1474
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 - 869 ft3 / T - 103 ft3
2420
1277' FSL, 342' FEL, Sec 27, T13N, R10W, SM, AK
2530' FSL, 189' FEL, Sec 27, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
887’ FSL, 757’ FWL, Sec 26, T13N, R10W, SM, AK AKA 029657
BRU 213-26
Beluga River Unit
Sterling - Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
7.31.2023
By Grace Christianson at 4:01 pm, Jul 31, 2023
A.Dewhurst 14 AUG 2023
Submit FIT/LOT data to AOGCC within 24 hrs of obtaining data.
BJM 9/7/23 DSR-8/4/23
223-069
BOP test to 3500 psi. Annular test to 2500 psi.
50-283-20192-00-00
($8
09/07/23
09/07/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.09.07 15:47:09 -08'00'
BRU 213-26
Drilling Program
Beluga River Unit
Rev 0
July 13, 2023
BRU 213-26
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 & NAD83)...............................................................................47
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Drilling Procedure
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1.0 Well Summary
Well BRU 213-26
Pad & Old Well Designation BRU H Pad –Grassroots Well
Planned Completion Type 4-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7,584 MD / 7,045’ TVD
PBTD, MD / TVD 7,504’ MD / 6,968’TVD
Surface Location (Governmental)887’ FSL, 757’ FWL, Sec 26, T13N, R10W, SM, AK
Surface Location (NAD 27)X=318697.65 Y=2626036.56
Surface Location (NAD 83)X=1458728.46 Y=2625790.23
Top of Productive Horizon
(Governmental)1277' FSL, 342' FEL, Sec 27, T13N, R10W, SM, AK
TPH Location (NAD 27)X=317608.24, Y=2626437.13
TPH Location (NAD 83)X=1457635.33 Y=2626197.62
BHL (Governmental)2530' FSL, 189' FEL, Sec 27, T13N, R10W, SM, AK
BHL (NAD 27)X=217780.15, Y=2627687.87
BHL (NAD 83)X=1457807.31 Y=2627488.34
AFE Number
AFE Drilling Days 25
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2420 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3125 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 98.2’(79.7 + 18.5)
Ground Elevation 79.7’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
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Drilling Procedure
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2.0 Management of Change Information
Page 4 Version 0 July, 2023
BRU 213-26
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).
Page 5 Version 0 July, 2023
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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. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
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
Page 6 Version 0 July, 2023
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6.0 Planned Wellbore Schematic
Page 7 Version 0 July, 2023
BRU 213-26
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7.0 Drilling / Completion Summary
BRU 213-26 is an S-shaped directional grassroots development well to be drilled from BRU H Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Sterling and Beluga sands.
The base plan is an S-shaped directional wellbore with a kickoff point at ~250’MD. Maximum hole angle
will be ~40 deg. and TD of the well will be 7,584’ TMD/ 7,045’ TVD, ending with 15 deg inclination left in
the hole. Vertical section will be 1889 ft.
Drilling operations are expected to commence approximately September 15th, 2023. The Hilcorp Rig # 147
will be used to drill the wellbore then run casing and cement.
Surface casing will be run to 2,895 MD / 2,533’ 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 BLM and 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 2,895’ 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 7,584’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 6% KCL 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 Pressure log dependent on hole conditions
Mud loggers from surface casing point to TD.
Page 8 Version 0 July, 2023
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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 and all
BLM regulations pertaining to Onshore Order No.1. 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 213-26. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man
office.
x Review all conditions of approval of the BLM APD and 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:
x Onshore Oil and Gas Order No. 1, Section III. D. 3. C.
o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve.
Operator suspects a freeze plug risk associated with installation of a check valve in the kill line.
o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping.
Page 9 Version 0 July, 2023
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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 APD.
Required BLM Notifications:
x 48 hours before spud. Follow up with actual spud date and time within 24 hours.
x 72 hours before casing running and cmt operations
x 72 hours before BOPE tests
x 72 hours before logging, coring, & testing
x Any other notifications required in APD
Additional requirements may be stipulated on APD and Sundry.
Page 10 Version 0 July, 2023
BRU 213-26
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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)
BLM
Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127
Email: aschoessler@blm.gov
Use the below email address for BOP notifications to the BLM:
BLM_AK_AKSO_EnergySection_Notifications@blm.gov
Page 11 Version 0 July, 2023
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9.0 R/U and Preparatory Work
9.1 Set 16” conductor at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install landing ring on conductor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 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.
Page 12 Version 0 July, 2023
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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 H 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 2,895’MD/ 2,533’ 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 2800’ MD and 3000’ 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
120-2,895’ 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. 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:
(2395’ –120’) x .03825 bpf x
1.75 =
152.28 855.0
Total LEAD:171.77 bbl 964.4 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(2895’- 2395’)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:204.13 bbl 1146.1 ft3
Verified cement calcs. -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:
2895’-80’ = 2815’x .04592 bpf = 130 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”.
Lead Slurry (2330’ MD to surface)Tail Slurry (2830’ to 2330’ MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.44 ft3/sk 1.16 ft3/sk
Mixed Water 14.40 gal/sk 5.03 gal/sk
Mixed Fluid 14.40 gal/sk 5.03 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
CalSeal Accelerator D-Air 5000 Anti Foam
VersaSet Thixotropic Calcium Chloride Accelerator
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner
BridgeMaker II Lost Circulation
Verified -bjm
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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.
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. Ensure to orient wellhead so that tree will line up with flowline later. 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 10/10 min.
x Ensure to leave 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
2,895’-7,584’9.0 –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 13.9 ppg EMW. Send the FIT results to the AOGCC within 48 hrs.
Note: Offset field test data predicts frac gradient at the 7-5/8”shoe to be between 11 - 15 ppg
EMW. A 13.9 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 7,584’ MD / 7,045’ 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 5,200’ 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 and E (3,982-4,599’ 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 performed in a previous BHA run, MU GeoTap BHA and RIH to perform pressure
sampling per geo.
15.19 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 6,790 ft-lbs 8,800 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:
(7084’ –2895’) x .02459 bpf x
1.4 =
144.21 809.7
Total LEAD:154.71 bbl 868.7 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(7584’- 7084’) 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 103.4 ft3
TOTAL CEMENT VOL:173.14 bbl 972.1 ft3
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Cement Slurry Design:
Lead Slurry (7084’ MD to 2695’ MD)Tail Slurry (7584’ to 7084’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.46 ft3/sk 1.22 ft3/sk
Mixed Water 14.349 gal/sk 5.507 gal/sk
Mixed Fluid 14.469 gal/sk 5.507 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
Halad-344 Fluid Loss Halad-344 Fluid Loss
HR-5 Retarder HR-5 Retarder
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add.FDP-C1446-21 Slurry Conditioner
SA-1015 Suspension Agent
BridgeMaker II Lost Circulation
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.
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17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
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
Page 33 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
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 6,790 ft-lbs 8,800 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
Page 34 Version 0 July, 2023
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Drilling Procedure
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20.0 Diverter Schematic
Page 35 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
21.0 BOP Schematic
Page 36 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
22.0 Wellhead Schematic
Page 37 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
23.0 Days Vs Depth
Page 38 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
24.0 Geo-Prog
Page 39 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
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.
Page 40 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 41 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
26.0 Hilcorp Rig 147 Layout
Page 42 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
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.
Page 43 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
28.0 Choke Manifold Schematic
Page 44 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
29.0 Casing Design Information
Page 45 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
30.0 6-3/4” Hole Section MASP
Page 46 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
31.0 Spider Plot w/ 660’ Radius for SSSV
Page 47 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
32.0 Surface Plat (As-Built NAD27 & NAD83)
Page 48 Version 0 July, 2023
BRU 213-26
Drilling Procedure
Rev 0
!
" #$$%
&
'
-500
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500
1000
1500
2000
2500
3000
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4000
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5000
5500
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7000
7500
Tr
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-500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000
Vertical Section at 330.00° (1000 usft/in)
BRU 213-26 tgt1
BRU 213-26 tgt2
7 5/8" x 9 7/8"
4 1/2" x 6 3/4"
50 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
7 5 8 5
BRU 213-26 wp04
Start Dir 3.75º/100' : 268.5' MD, 268.5'TVD
End Dir : 1332.79' MD, 1248.78' TVD
Start Dir 4º/100' : 1534.23' MD, 1403.3'TVD
End Dir : 2079.33' MD, 1831.87' TVD
Start Dir 3º/100' : 2179.33' MD, 1910.51'TVD
End Dir : 3267.89' MD, 2884.93' TVD
Start Dir 2º/100' : 4157.46' MD, 3734.61'TVD
End Dir : 4286.69' MD, 3858.76' TVD
Total Depth : 7585.33' MD, 7045' TVD
BRU_ST_A1_COAL
STERLING_B
STERLING_C
BELUGA_D
BELUGA_E
BELUGA_F
BELUGA_G
BELUGA_H
BELUGA_I
BRU_BELUGA_J
BRU_BELUGA_J6
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 213-26
79.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2626036.56 318697.65 61° 11' 1.4316 N 151° 1' 38.4621 W
SURVEY PROGRAM
Date: 2023-07-07T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2894.00 BRU 213-26 wp04 (BRU 213-26) 3_MWD+AX+Sag
2894.00 7585.33 BRU 213-26 wp04 (BRU 213-26) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3006.20 2908.00 3394.85 BRU_ST_A1_COAL
3212.20 3114.00 3610.53 STERLING_B
3360.20 3262.00 3765.48 STERLING_C
3568.20 3470.00 3983.24 BELUGA_D
3782.20 3684.00 4207.17 BELUGA_E
4161.20 4063.00 4599.80 BELUGA_F
4690.20 4592.00 5147.46 BELUGA_G
5067.20 4969.00 5537.76 BELUGA_H
5827.20 5729.00 6324.57 BELUGA_I
6390.20 6292.00 6907.43 BRU_BELUGA_J
6900.20 6802.00 7435.42 BRU_BELUGA_J6
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 213-26, True North
Vertical (TVD) Reference:As-Built RKB @ 98.20usft (HEC 147)
Measured Depth Reference:As-Built RKB @ 98.20usft (HEC 147)
Calculation Method:Minimum Curvature
Project:Beluga River
Site:BRU H-Pad
Well:BRU 213-26
Wellbore:BRU 213-26
Design:BRU 213-26 wp04
CASING DETAILS
TVD TVDSS MD Size Name
2533.00 2434.80 2895.84 7-5/8 7 5/8" x 9 7/8"
7045.00 6946.80 7585.33 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
2 268.50 0.00 0.00 268.50 0.00 0.00 0.00 0.00 0.00 Start Dir 3.75º/100' : 268.5' MD, 268.5'TVD
3 1332.79 39.91 270.15 1248.78 0.95 -355.93 3.75 270.15 178.79 End Dir : 1332.79' MD, 1248.78' TVD
4 1534.23 39.91 270.15 1403.30 1.30 -485.17 0.00 0.00 243.71 Start Dir 4º/100' : 1534.23' MD, 1403.3'TVD
5 2079.33 38.15 305.00 1831.87 99.52 -801.78 4.00 108.15 487.08 End Dir : 2079.33' MD, 1831.87' TVD
6 2179.33 38.15 305.00 1910.51 134.95 -852.38 0.00 0.00 543.06 BRU 213-26 tgt1 Start Dir 3º/100' : 2179.33' MD, 1910.51'TVD
7 3267.89 17.22 5.24 2884.93 498.18 -1120.36 3.00 151.55 991.62 End Dir : 3267.89' MD, 2884.93' TVD
8 4157.46 17.22 5.24 3734.61 760.48 -1096.29 0.00 0.00 1206.74 Start Dir 2º/100' : 4157.46' MD, 3734.61'TVD
9 4286.69 15.00 10.00 3858.76 796.01 -1091.64 2.00 151.57 1235.18 End Dir : 4286.69' MD, 3858.76' TVD
10 6286.69 15.00 10.00 5790.61 1305.79 -1001.75 0.00 0.00 1631.72 BRU 213-26 tgt2
11 7585.33 15.00 10.00 7045.00 1636.79 -943.38 0.00 0.00 1889.20 Total Depth : 7585.33' MD, 7045' TVD
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
So
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-1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0
West(-)/East(+) (200 usft/in)
BRU 213-26 tgt2
BRU 213-26 tgt1
7 5/8" x 9 7/8"
4 1/2" x 6 3/4"
250
500
750
1000
1250
1500
1750
2000
2250
2 5 0 0
2 7 5 0
3 0 0 0
3250
3500
3750
4000
4250
4500
4750
5000
5250
5500
5750
6000
6250
6500
6750
7000
7250
7500
7585 BRU 213-26 wp04
Start Dir 3.75º/100' : 268.5' MD, 268.5'TVD
End Dir : 1332.79' MD, 1248.78' TVD
Start Dir 4º/100' : 1534.23' MD, 1403.3'TVD
End Dir : 2079.33' MD, 1831.87' TVD
Start Dir 3º/100' : 2179.33' MD, 1910.51'TVD
End Dir : 3267.89' MD, 2884.93' TVD
Start Dir 2º/100' : 4157.46' MD, 3734.61'TVD
End Dir : 4286.69' MD, 3858.76' TVD
Total Depth : 7585.33' MD, 7045' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2533.00 2434.80 2895.84 7-5/8 7 5/8" x 9 7/8"
7045.00 6946.80 7585.33 4-1/2 4 1/2" x 6 3/4"
Project: Beluga River
Site: BRU H-Pad
Well: BRU 213-26
Wellbore: BRU 213-26
Plan: BRU 213-26 wp04
WELL DETAILS: BRU 213-26
79.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2626036.56 318697.65 61° 11' 1.4316 N 151° 1' 38.4621 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 213-26, True North
Vertical (TVD) Reference: As-Built RKB @ 98.20usft (HEC 147)
Measured Depth Reference:As-Built RKB @ 98.20usft (HEC 147)
Calculation Method:Minimum Curvature
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0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075
Measured Depth (850 usft/in)
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
NOERRORS
WELL DETAILS:BRU 213-26 NAD 1927 (NADCON CONUS)Alaska Zone 04
79.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2626036.56 318697.65 61° 11' 1.4316 N 151° 1' 38.4621 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 213-26, True North
Vertical (TVD) Reference:As-Built RKB @ 98.20usft (HEC 147)
Measured Depth Reference:As-Built RKB @ 98.20usft (HEC 147)
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-07-07T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2894.00 BRU 213-26 wp04 (BRU 213-26) 3_MWD+AX+Sag
2894.00 7585.33 BRU 213-26 wp04 (BRU 213-26) 3_MWD+AX+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
Ce
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0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075
Measured Depth (850 usft/in)
BRU 212-26
BRU 214-26
BRU 214-26PB1
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
18.50 To 7585.33
Project: Beluga River
Site: BRU H-Pad
Well: BRU 213-26
Wellbore: BRU 213-26
Plan: BRU 213-26 wp04
CASING DETAILS
TVD TVDSS MD Size Name
2533.00 2434.80 2895.84 7-5/8 7 5/8" x 9 7/8"
7045.00 6946.80 7585.33 4-1/2 4 1/2" x 6 3/4"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
BELUGA RIVER UNIT
STERLING, BELUGA UNDEFINED GAS
BRU 213-26
223-069
x
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:BELUGA RIV UNIT 213-26
Initial Class/Type DEV / PEND GeoArea 820 Unit 50220 On/Off Shore On
Program DEVField & Pool Well bore seg
Annular DisposalPTD#:2230690
STERLING, BELUGA UNDEFINED GAS - 768520
NA1 Permit fee attached
Yes AKA 0296572 Lease number appropriate
Yes3 Unique well name and number
Yes BELUGA RIVER, Sterling-Beluga Gas Pool – 92500, governed by CO 8024 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv
NA15 All wells within 1/4 mile area of review identified (For service well only)
NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)
NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
Yes18 Conductor string provided
Yes19 Surface casing protects all known USDWs
Yes20 CMT vol adequate to circulate on conductor & surf csg
Yes21 CMT vol adequate to tie-in long string to surf csg
Yes22 CMT will cover all known productive horizons
Yes23 Casing designs adequate for C, T, B & permafrost
Yes24 Adequate tankage or reserve pit
NA25 If a re-drill, has a 10-403 for abandonment been approved
Yes26 Adequate wellbore separation proposed
Yes27 If diverter required, does it meet regulations
Yes28 Drilling fluid program schematic & equip list adequate
Yes29 BOPEs, do they meet regulation
Yes MPSP = 2420 psi, BOP rated to 5k, (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)
Yes31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
No33 Is presence of H2S gas probable
NA34 Mechanical condition of wells within AOR verified (For service well only)
Yes H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measures
Yes Many sands encountered are expected to be severely under-pressured36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
ADD
Date
8/14/2023
Appr
BJM
Date
9/7/2023
Appr
ADD
Date
8/14/2023
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
*&:
