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HomeMy WebLinkAbout223-050Nolan 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 211-35 50283201890000 223050 11/7/2025 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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CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson; Maercklein, William C
Cc:Donna Ambruz; Starns, Ted C (OGC); Trevor Willms - (C)
Subject:RE: BRU 211-35 (PTD# 223-050) Sundry update
Date:Thursday, November 6, 2025 12:53:00 PM
Chad,
Hilcorp has approval to proceed with the perfs according to the new procedure, which
were correctly noted on the proposed wellbore diagram of the original sundry 325-637.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Thursday, November 6, 2025 11:44 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Maercklein, William C
<wmaercklein@blm.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Trevor
Willms - (C) <Trevor.Willms@hilcorp.com>
Subject: BRU 211-35 (PTD# 223-050) Sundry update
We were getting ready to start perforating (tomorrow) on BRU 211-35 (PTD# 223-050) and
realized that we attached the procedure with the incorrect proposed perfs in the procedure.
The proposed schematic in the original submission was correct, but they did not match what
was listed int eh procedure. The table included zones that were already perforated. The goal
of this project is to perforate one E sand we skipped and shoot the Beluga D sands.
Attached is the procedure that should have been included with the application.
Is it possible for us to get approval for the proposed perfs via this email, or will a formal change
of program need to be submitted.
Sorry for the mistake.
Chad Helgeson
Operations Engineer
Kenai Asset Team
907-777-8405 - O
907-229-4824 - C
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Well Prognosis
Well Name: BRU 211-35 API Number: 50-283-20189-00-00
Current Status: Gas Producer Permit to Drill Number: 223-050
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: 1782 psi @ 4143 (Based on 0.43 psi/ft gradient))
Max. Potential Surface Pressure: 1659 psi (Based on 0.03 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.722 psi/ft using 13.9 ppg EMW FIT at the Surface shoe (2785ft)
Shallowest Allowable Perf TVD: MPSP/(0.722-0.03) = 1659 psi / 0.692 = 2,397
Top of SBGP (CO 802A): ~3,046 MD/ ~2,824
Brief Well Summary
Drilled & completed in 2023, BRU 211-35 is an online producer in the Beluga River Unit (BRU) Sterling-Beluga Gas
Pool (SBGP) with a 3-The Beluga 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.
Wellbore Conditions:
Flowing at ~2887mcf @ 170 psi with 5 bwpd
3-1/2 TOC @ ~2630 from CBL 7-31-23
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 ~3,046 ~2,824'
BEL D ±3,839' ±3,842' ±3,610' ±3,613' ±3'
BEL D1 ±3,857' ±3,873' ±3,628' ±3,644' ±16'
BEL D2 ±3,885' ±3,889' ±3,656' ±3,660' ±4'
BEL D3 ±3,905' ±3,912' ±3,676' ±3,683' ±7'
BEL D3 ±3,916' ±3,922' ±3,687' ±3,693' ±6'
BEL D4 ±3,935' ±3,940' ±3,706' ±3,711' ±5'
BEL D5 ±3,969' ±3,977' ±3,740' ±3,748' ±8'
BEL D6 ±4,005' ±4,015' ±3,775' ±3,785' ±10'
BEL D7 ±4,028' ±4,040' ±3,798' ±3,810' ±12'
BEL E3 ±4,172' ±4,180' ±3,941' ±3,949' ±8'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other:
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,199' N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; Baker ONYX TRSSSV 2,597' MD/ 2,396' TVD; 174' MD/TVD
6,938' 6,233' 5,986'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 211-35CO 802A
Same
6,936'3-1/2"
~1659psi
4,559'
6,268'
Length
October 24, 2025
Tieback 3-1/2"
7,156'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
2,785'
Size
120'
2,785'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
2,404'
10,160psi
2,565'
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
223-050
50-283-20189-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
chelgeson@hilcorp.com
907-777-8405
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
325-637
By Gavin Gluyas at 10:01 am, Oct 16, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.10.15 17:00:04 -
08'00'
Noel Nocas
(4361)
DSR-10/16/25
10-404
TS 10/21/25
BJM 10/20/25
10/22/25
Well Prognosis
Well Name: BRU 211-35 API Number: 50-283-20189-00-00
Current Status: Gas Producer Permit to Drill Number: 223-050
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: 1782 psi @ 4143 TVD (Based on 0.43 psi/ft gradient))
Max. Potential Surface Pressure: 1659 psi (Based on 0.03 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.722 psi/ft using 13.9 ppg EMW FIT at the Surface shoe (2785ft)
Shallowest Allowable Perf TVD: MPSP/(0.722-0.03) = 1659 psi / 0.692 = 2,397 TVD
Top of SBGP (CO 802A): ~3,046 MD/ ~2,824 TVD
Brief Well Summary
Drilled & completed in 2023, BRU 211-35 is an online producer in the Beluga River Unit (BRU) Sterling-Beluga Gas
Pool (SBGP) with a 3-1/2 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:
Flowing at ~2450mcf @ 215 psi with 5 bwpd
3-1/2 TOC @ ~2630 from CBL 7-31-23
2.5 DD Bailer tagged @ 5886 on 10-22-24
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
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
Formation MD TOP MD BASE TVD TOP TVD BASE H
Top Pool ~3,046 ~2,824'
Bel E1 ±4,066 ±4,078 ±3,836 ±3,848 ±12
Bel E1 ±4,089 ±4,098 ±3,859 ±3,868 ±9
Bel E1 ±4,103 ±4,111 ±3,873 ±3,881 ±8
Bel E2 ±4,127 ±4,142 ±3,897 ±3,912 ±15
Bel E3 ±4,209 ±4,218 ±3,978 ±3,987 ±9
Bel E5 ±4,243 ±4,256 ±4,012 ±4,025 ±13
Bel E5 ±4,321 ±4,326 ±4,090 ±4,094 ±5
Bel E6 ±4,347 ±4,355 ±4,115 ±4,123 ±8
Bel E6 ±4,360 ±4,375 ±4,128 ±4,143 ±15
Updated by DMA 06-18-25
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,086 MD / TVD = 6,831
TD = 7,199 MD / TVD = 6,944
RKB to GL = 19.9
Bel I Bel J
Bel F
Bel G
Bel H
Bel E
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface
3-1/2 TOC @ 2630 (CBL 7-31-23)
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 2,785
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992 2,597 7,156
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992 Surf 2,605
3
16
7-5/8
9-7/8
hole
3-1/2
JEWELRY DETAIL
No. Depth ID OD Item
Cactus CTF-ONE-CTL Hanger w/ 2G LH lift Thrd 4 type H BPV
1 174 2.830 5.180 Baker ONYX-5RE TRSSSV
2 1,526 2.992 4.780 Chemical Injection Mandrel
3 2,605 4.780 6.370 Seal Stem (10) w/ WEG, Liner hanger / LTP Assembly
4 6,268 - 2.280 CIBP w/ 35 cmt (TOC @ 6,233 MD)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool: 3,046 MD: 2824 TVD
Bel E1 4,066 4,078 3,836 3,848 12 6/12/25 Open
Bel E1 4,089 4,098 3,859 3,868 9 6/12/25 Open
Bel E1 4,103 4,110 3,874 3,880 6 6/3/25 Open
Bel E2 4,127 4,142 3,897 3,912 15 6/3/25 Open
Bel E3 4,209 4,218 3,978 3,987 9 6/3/25 Open
Bel E5 4,243 4,256 4,012 4,025 13 6/3/25 Open
Bel E5 4,321 4,326 4,090 4,094 5 6/3/25 Open
Bel E6 4,347 4,355 4,115 4,123 8 6/2/25 Open
Bel E6 4,360 4,374 4,128 4,142 14 6/2/25 Open
Bel F 4,443 4,452 4,210 4,219 9 8/19/23 Open
Bel F 4,505 4,518 4,272 4,285 13 8/19/23 Open
Bel F 4,545 4,553 4,312 4,320 8 8/19/23 Open
Bel F 4,556 4,562 4,323 4,329 6 8/19/23 Open
Bel F 4,576 4,582 4,342 4,348 6 8/19/23 Open
Bel F 4,605 4,613 4,371 4,379 8 8/19/23 Open
Bel F 4,629 4,641 4,392 4,404 12 8/19/23 Open
Bel F 4,682 4,687 4,448 4,453 5 8/19/23 Open
Bel F 4,704 4,714 4,470 4,480 10 8/19/23 Open
Bel F 4,731 4,743 4,497 4,509 12 8/19/23 Open
Bel F 4,765 4,775 4,531 4,541 10 8/19/23 Open
Bel F 4,797 4,811 4,563 4,577 14 8/19/23 Open
Bel F 4,855 4,861 4,610 4,616 6 8/19/23 Open
Bel G 4,945 4,954 4,709 4,718 9 8/18/23 Open
Bel G 4,979 4,989 4,743 4,753 10 8/18/23 Open
Bel G 5,005 5,017 4,769 4,781 12 8/18/23 Open
Bel G 5,027 5,037 4,791 4,801 10 8/18/23 Open
Bel G 5,069 5,075 4,832 4,838 6 8/18/23 Open
Bel G 5,091 5,109 4,854 4,872 18 8/17/23 Open
Bel G 5,143 5,155 4,905 4,917 12 8/17/23 Open
Bel G 5,181 5,187 4,943 4,949 6 8/17/23 Open
Bel G 5,204 5,210 4,966 4,972 6 8/17/23 Open
Bel G 5,217 5,222 4,979 4,984 5 8/17/23 Open
Bel G 5,237 5,243 4,999 5,005 6 8/17/23 Open
Bel H 5,366 5,372 5,136 5,142 6 8/15/23 Open
Bel H 5,398 5,418 5,159 5,179 20 8/15/23 Open
Bel H 5,493 5,499 5,253 5,259 6 8/15/23 Open
Bel H 5,512 5,518 5,272 5,278 6 8/15/23 Open
(continued on following page)
6-3/4
hole
2
1
4
Page 2 Updated by DMA 06-18-25
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PERFORATION DETAIL (continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel H 5,530 5,535 5,290 5,295 5 8/14/23 Open
Bel H 5,555 5,561 5,314 5,320 6 8/14/23 Open
Bel H 5,610 5,630 5,371 5,390 20 8/14/23 Open
Bel H 5,637 5,643 5,396 5,402 6 8/14/23 Open
Bel H 5,660 5,672 5,418 5,430 12 8/13/23 Open
Bel H 5,672 5,697 5,430 5,454 25 8/13/23 Open
Bel H 5,957 5,982 5,712 5,736 25 8/13/23 Open
Bel I 6,318 6,332 6,069 6,083 14 8/2/23 Plugged
Bel J 6,635 6,648 6,385 6,398 13 8/2/23 Plugged
Bel J 6,911 6,921 6,658 6,668 10 8/2/23 Plugged
Updated by DMA 08-28-25
PROPOSED
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,086 MD / TVD = 6,831
TD = 7,199 MD / TVD = 6,944
RKB to GL = 19.9
Bel I Bel J
Bel F
Bel G
Bel H
Bel E
Bel D
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface
3-1/2 TOC @ 2630 (CBL 7-31-23)
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 2,785
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992 2,597 7,156
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992 Surf 2,605
3
16
7-5/8
9-7/8
hole
3-1/2
JEWELRY DETAIL
No. Depth ID OD Item
Cactus CTF-ONE-CTL Hanger w/ 2G LH lift Thrd 4 type H BPV
1 174 2.830 5.180 Baker ONYX-5RE TRSSSV
2 1,526 2.992 4.780 Chemical Injection Mandrel
3 2,605 4.780 6.370 Seal Stem (10) w/ WEG, Liner hanger / LTP Assembly
4 6,268 - 2.280 CIBP w/ 35 cmt (TOC @ 6,233 MD)
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool: 3,046 MD: 2,824 TVD
BEL D ±3,839' ±3,842' ±3,610' ±3,613' ±3' Proposed TBD
BEL D1 ±3,857' ±3,873' ±3,628' ±3,644' ±16' Proposed TBD
BEL D2 ±3,885' ±3,889' ±3,656' ±3,660' ±4' Proposed TBD
BEL D3 ±3,905' ±3,912' ±3,676' ±3,683' ±7' Proposed TBD
BEL D3 ±3,916' ±3,922' ±3,687' ±3,693' ±6' Proposed TBD
BEL D4 ±3,935' ±3,940' ±3,706' ±3,711' ±5' Proposed TBD
BEL D5 ±3,969' ±3,977' ±3,740' ±3,748' ±8' Proposed TBD
BEL D6 ±4,005' ±4,015' ±3,775' ±3,785' ±10' Proposed TBD
BEL D7 ±4,028' ±4,040' ±3,798' ±3,810' ±12' Proposed TBD
Bel E1 4,066 4,078 3,836 3,848 12 6/12/25 Open
Bel E1 4,089 4,098 3,859 3,868 9 6/12/25 Open
Bel E1 4,103 4,110 3,874 3,880 6 6/3/25 Open
Bel E2 4,127 4,142 3,897 3,912 15 6/3/25 Open
BEL E3 ±4,172' ±4,180' ±3,941' ±3,949' ±8' Proposed TBD
Bel E3 4,209 4,218 3,978 3,987 9 6/3/25 Open
Bel E5 4,243 4,256 4,012 4,025 13 6/3/25 Open
Bel E5 4,321 4,326 4,090 4,094 5 6/3/25 Open
Bel E6 4,347 4,355 4,115 4,123 8 6/2/25 Open
Bel E6 4,360 4,374 4,128 4,142 14 6/2/25 Open
Bel F 4,443 4,452 4,210 4,219 9 8/19/23 Open
Bel F 4,505 4,518 4,272 4,285 13 8/19/23 Open
Bel F 4,545 4,553 4,312 4,320 8 8/19/23 Open
Bel F 4,556 4,562 4,323 4,329 6 8/19/23 Open
Bel F 4,576 4,582 4,342 4,348 6 8/19/23 Open
Bel F 4,605 4,613 4,371 4,379 8 8/19/23 Open
Bel F 4,629 4,641 4,392 4,404 12 8/19/23 Open
Bel F 4,682 4,687 4,448 4,453 5 8/19/23 Open
Bel F 4,704 4,714 4,470 4,480 10 8/19/23 Open
Bel F 4,731 4,743 4,497 4,509 12 8/19/23 Open
Bel F 4,765 4,775 4,531 4,541 10 8/19/23 Open
Bel F 4,797 4,811 4,563 4,577 14 8/19/23 Open
Bel F 4,855 4,861 4,610 4,616 6 8/19/23 Open
(continued on following page)
6-3/4
hole
2
1
4
Updated by DMA 08-28-25
PROPOSED
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PERFORATION DETAIL (continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel G 4,945 4,954 4,709 4,718 9 8/18/23 Open
Bel G 4,979 4,989 4,743 4,753 10 8/18/23 Open
Bel G 5,005 5,017 4,769 4,781 12 8/18/23 Open
Bel G 5,027 5,037 4,791 4,801 10 8/18/23 Open
Bel G 5,069 5,075 4,832 4,838 6 8/18/23 Open
Bel G 5,091 5,109 4,854 4,872 18 8/17/23 Open
Bel G 5,143 5,155 4,905 4,917 12 8/17/23 Open
Bel G 5,181 5,187 4,943 4,949 6 8/17/23 Open
Bel G 5,204 5,210 4,966 4,972 6 8/17/23 Open
Bel G 5,217 5,222 4,979 4,984 5 8/17/23 Open
Bel G 5,237 5,243 4,999 5,005 6 8/17/23 Open
Bel H 5,366 5,372 5,136 5,142 6 8/15/23 Open
Bel H 5,398 5,418 5,159 5,179 20 8/15/23 Open
Bel H 5,493 5,499 5,253 5,259 6 8/15/23 Open
Bel H 5,512 5,518 5,272 5,278 6 8/15/23 Open
Bel H 5,530 5,535 5,290 5,295 5 8/14/23 Open
Bel H 5,555 5,561 5,314 5,320 6 8/14/23 Open
Bel H 5,610 5,630 5,371 5,390 20 8/14/23 Open
Bel H 5,637 5,643 5,396 5,402 6 8/14/23 Open
Bel H 5,660 5,672 5,418 5,430 12 8/13/23 Open
Bel H 5,672 5,697 5,430 5,454 25 8/13/23 Open
Bel H 5,957 5,982 5,712 5,736 25 8/13/23 Open
Bel I 6,318 6,332 6,069 6,083 14 8/2/23 Plugged
Bel J 6,635 6,648 6,385 6,398 13 8/2/23 Plugged
Bel J 6,911 6,921 6,658 6,668 10 8/2/23 Plugged
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.
T40743BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf
T40743BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF
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 211-35 50283201890000 223050 6/2/2025 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 7,199 feet 6,268 feet
true vertical 5,938 feet N/A feet
Effective Depth measured 6,233 feet 2,597 feet
true vertical 5,986 feet 2,396 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) Tieback 3-1/2" 9.2# / L-80 2,605' MD 2,404' TVD
TRSSSV-ONYX 174' MD/TVD
Packers and SSSV (type, measured and true vertical depth) ZXPN LTP Baker 2,597' MD 2,396' TVD
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:
10,540psi
2,980psi
6,890psi
10,160psi
2,785' 2,565'
Burst Collapse
1,410psi
4,790psi
Production
Liner
4,559'
Casing
Structural
6,936'7,156'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
2,785'
measured
TVD
3-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-050
50-283-20189-00-00
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) 211-35
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
120'
3 03022
0 2000
213
Chad Helgeson, Operations Engineer
325-117
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
2409
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
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 8:21 am, Jul 11, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.07.10 18:46:23 -
08'00'
Noel Nocas
(4361)
BJM 9/25/25
Page 1/1
Well Name: BRU 211-35
Report Printed: 6/18/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-283-20189-00-00 Field Name:Beluga River State/Province:ALASKA
Permit to Drill (PTD) #:223-050 Sundry #:325-117 Rig Name/No:
Jobs
Actual Start Date:2/13/2025 End Date:
Report Number
1
Report Start Date
6/2/2025
Report End Date
6/3/2025
Last 24hr Summary
AK E-line Adperf. Fly crew to Beluga. PJSM / PTW. Move equipment to location and rig up. T/I: 195/0 psi. PT 250/2500 psi. RIH w/ 2" GEO Razor 6 SPF, 60* Phsg,
6.8 gms. Perforate Bel E6 4360 - 4374' @ 296 psi FTP. RIH w/ gun #2. Perf Bel E6 4,347 - 4,355. FTP 304 psi. POH. RDFN. Turn well over to Ops.
Report Number
2
Report Start Date
6/3/2025
Report End Date
6/4/2025
Last 24hr Summary
AK E-Line Adperf. PJSM/PTW. Rig up T/I 195/0 psi. Pinch choke to 300 psi FTP. RIH and perforate the following intervals each in separate runs. Bel E5 4321 -
4326'. Bel E5 4,243 - 4,256. Bel E3 4,209 - 4,218'. Bel E2 4127 - 4142'. Bel E1 4104 4110. Perf guns: 2" GEO Razor 6 SPF, 60* Phsg, 6.8 gms. Note: Two
intervals remain to be shot when 2" guns available.
Report Number
3
Report Start Date
6/11/2025
Report End Date
6/12/2025
Last 24hr Summary
PJSM, Crew mob from k-pad to E-pad, Spot in & rig up.
Report Number
4
Report Start Date
6/12/2025
Report End Date
6/13/2025
Last 24hr Summary
PJSM, Crew travel to location, Pick up lube & tool string (1 x CCL/GR, 1 x wt bar, 1 x 2" x 9' gun), Pressure test lube 250/2000-good, Run in the hole with run #1,
Correlate, Perf E1 4089-4098, Pull out of hole, Pick up & make up run #2 string (1 x CCL/GR, 1 x wt bar, 1 x 2" x 12' gun), Run in the hole, Perf BEL E1 4066-4078,
Pull out of the hole, Rig down & release AK eline.
Updated by DMA 06-18-25
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,086 MD / TVD = 6,831
TD = 7,199 MD / TVD = 6,944
RKB to GL = 19.9
Bel I Bel J
Bel F
Bel G
Bel H
Bel E
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface
3-1/2 TOC @ 2630 (CBL 7-31-23)
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 2,785
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992 2,597 7,156
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992 Surf 2,605
3
16
7-5/8
9-7/8
hole
3-1/2
JEWELRY DETAIL
No. Depth ID OD Item
Cactus CTF-ONE-CTL Hanger w/ 2G LH lift Thrd 4 type H BPV
1 174 2.830 5.180 Baker ONYX-5RE TRSSSV
2 1,526 2.992 4.780 Chemical Injection Mandrel
3 2,605 4.780 6.370 Seal Stem (10) w/ WEG, Liner hanger / LTP Assembly
4 6,268 - 2.280 CIBP w/ 35 cmt (TOC @ 6,233 MD)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool: 3,046 MD: 2824 TVD
Bel E1 4,066 4,078 3,836 3,848 12 6/12/25 Open
Bel E1 4,089 4,098 3,859 3,868 9 6/12/25 Open
Bel E1 4,103 4,110 3,874 3,880 6 6/3/25 Open
Bel E2 4,127 4,142 3,897 3,912 15 6/3/25 Open
Bel E3 4,209 4,218 3,978 3,987 9 6/3/25 Open
Bel E5 4,243 4,256 4,012 4,025 13 6/3/25 Open
Bel E5 4,321 4,326 4,090 4,094 5 6/3/25 Open
Bel E6 4,347 4,355 4,115 4,123 8 6/2/25 Open
Bel E6 4,360 4,374 4,128 4,142 14 6/2/25 Open
Bel F 4,443 4,452 4,210 4,219 9 8/19/23 Open
Bel F 4,505 4,518 4,272 4,285 13 8/19/23 Open
Bel F 4,545 4,553 4,312 4,320 8 8/19/23 Open
Bel F 4,556 4,562 4,323 4,329 6 8/19/23 Open
Bel F 4,576 4,582 4,342 4,348 6 8/19/23 Open
Bel F 4,605 4,613 4,371 4,379 8 8/19/23 Open
Bel F 4,629 4,641 4,392 4,404 12 8/19/23 Open
Bel F 4,682 4,687 4,448 4,453 5 8/19/23 Open
Bel F 4,704 4,714 4,470 4,480 10 8/19/23 Open
Bel F 4,731 4,743 4,497 4,509 12 8/19/23 Open
Bel F 4,765 4,775 4,531 4,541 10 8/19/23 Open
Bel F 4,797 4,811 4,563 4,577 14 8/19/23 Open
Bel F 4,855 4,861 4,610 4,616 6 8/19/23 Open
Bel G 4,945 4,954 4,709 4,718 9 8/18/23 Open
Bel G 4,979 4,989 4,743 4,753 10 8/18/23 Open
Bel G 5,005 5,017 4,769 4,781 12 8/18/23 Open
Bel G 5,027 5,037 4,791 4,801 10 8/18/23 Open
Bel G 5,069 5,075 4,832 4,838 6 8/18/23 Open
Bel G 5,091 5,109 4,854 4,872 18 8/17/23 Open
Bel G 5,143 5,155 4,905 4,917 12 8/17/23 Open
Bel G 5,181 5,187 4,943 4,949 6 8/17/23 Open
Bel G 5,204 5,210 4,966 4,972 6 8/17/23 Open
Bel G 5,217 5,222 4,979 4,984 5 8/17/23 Open
Bel G 5,237 5,243 4,999 5,005 6 8/17/23 Open
Bel H 5,366 5,372 5,136 5,142 6 8/15/23 Open
Bel H 5,398 5,418 5,159 5,179 20 8/15/23 Open
Bel H 5,493 5,499 5,253 5,259 6 8/15/23 Open
Bel H 5,512 5,518 5,272 5,278 6 8/15/23 Open
(continued on following page)
6-3/4
hole
2
1
4
Page 2 Updated by DMA 06-18-25
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PERFORATION DETAIL (continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel H 5,530 5,535 5,290 5,295 5 8/14/23 Open
Bel H 5,555 5,561 5,314 5,320 6 8/14/23 Open
Bel H 5,610 5,630 5,371 5,390 20 8/14/23 Open
Bel H 5,637 5,643 5,396 5,402 6 8/14/23 Open
Bel H 5,660 5,672 5,418 5,430 12 8/13/23 Open
Bel H 5,672 5,697 5,430 5,454 25 8/13/23 Open
Bel H 5,957 5,982 5,712 5,736 25 8/13/23 Open
Bel I 6,318 6,332 6,069 6,083 14 8/2/23 Plugged
Bel J 6,635 6,648 6,385 6,398 13 8/2/23 Plugged
Bel J 6,911 6,921 6,658 6,668 10 8/2/23 Plugged
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other:
2.Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6.API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,199'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; Baker ONYX TRSSSV 2,597' MD/ 2,396' TVD; 174' MD/TVD
6,938'6,233'5,986'
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) 211-35CO 802A
Same
6,936'3-1/2"
~1659psi
4,559'
6,268'
Length
March 14, 2025
Tieback 3-1/2"
7,156'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
2,785'
Size
120'
2,785'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
2,605'
10,160psi
2,565'
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
223-050
50-283-20189-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
chelgeson@hilcorp.com
907-777-8405
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
325-117
By Gavin Gluyas at 8:08 am, Mar 03, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.02.28 10:47:29 -
09'00'
Noel Nocas
(4361)
2000 psi -bjm
DSR-3/10/25
10-404
BJM 3/18/25
A.Dewhurst 05MAR25*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.03.19 10:22:29 -08'00'03/19/25
RBDMS JSB 032125
Well Prognosis
Well Name: BRU 211-35 API Number: 50-283-20189-00-00
Current Status: Gas Producer Permit to Drill Number: 223-050
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: 1782 psi @ 4143’ TVD (Based on 0.43 psi/ft gradient))
Max. Potential Surface Pressure: 1659 psi (Based on 0.03 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.722 psi/ft using 13.9 ppg EMW FIT at the Surface shoe (2785ft)
Shallowest Allowable Perf TVD: MPSP/(0.722-0.03) = 1659 psi / 0.692 = 2,397‘ TVD
Top of SBGP (CO 802A): ~3,046’ MD/ ~2,824’ TVD
Brief Well Summary
Drilled & completed in 2023, BRU 211-35 is an online producer in the Beluga River Unit (BRU) Sterling-Beluga Gas
Pool (SBGP) with a 3-1/2” 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 ~2450mcf @ 215 psi with 5 bwpd
x 3-1/2” TOC @ ~2630’ from CBL 7-31-23
x 2.5” DD Bailer tagged @ 5886’ on 10-22-24
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
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
Formation MD TOP MD BASE TVD TOP TVD BASE H
Top Pool ~3,046 ~2,824'
Bel E1 ±4,066‘ ±4,078‘ ±3,836’ ±3,848’ ±12
Bel E1 ±4,089’ ±4,098‘ ±3,859’ ±3,868’ ±9
Bel E1 ±4,103’ ±4,111‘ ±3,873’ ±3,881’ ±8
Bel E2 ±4,127’ ±4,142’ ±3,897’ ±3,912’ ±15
Bel E3 ±4,209’ ±4,218‘ ±3,978’ ±3,987’ ±9
Bel E5 ±4,243’ ±4,256‘ ±4,012’ ±4,025’ ±13
Bel E5 ±4,321’ ±4,326’ ±4,090’ ±4,094’ ±5
Bel E6 ±4,347’ ±4,355’ ±4,115’ ±4,123’ ±8
Bel E6 ±4,360’ ±4,375’ ±4,128’ ±4,143’ ±15
See attached email. -bjm
0.6920.03)
-bjmMax BHP & MPSP should be calculated on deepest open perf @5712' TVD.
MPSP should be based on reservoir pressure at deepest perf unless data shows
the reservoire pressure at those perfs to be lower.
Updated by CAH 01-09-25
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,086’ MD / TVD = 6,831’
TD = 7,199’ MD / TVD = 6,944’
RKB to GL = 19.9’
Bel I – Bel J
Bel F
Bel G
Bel H
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface
3-1/2” TOC @ 2630’ (CBL)
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 TXP 6.875” Surf 2,785’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,597’ 7,156’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,605’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
Cactus CTF-ONE-CTL Hanger w/ 2G LH lift Thrd 4” type H BPV
1 174’ 2.830” 5.180” Baker ONYX-5RE TRSSSV
2 1,526’ 2.813” 4.780” Chemical Injection Sub
3 2,605’ 4.780” 6.370” Seal Stem (10’) w/ WEG, Liner hanger / LTP Assembly
4 6,268’ - 2.280” CIBP w/ 35’ cmt (TOC @ 6,233’ MD)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel F 4,443’ 4,452’ 4,210’ 4,219’ 9 8/19/23 Open
Bel F 4,505’ 4,518’ 4,272’ 4,285’ 13 8/19/23 Open
Bel F 4,545’ 4,553’ 4,312’ 4,320’ 8 8/19/23 Open
Bel F 4,556’ 4,562’ 4,323’ 4,329’ 6 8/19/23 Open
Bel F 4,576’ 4,582’ 4,342’ 4,348’ 6 8/19/23 Open
Bel F 4,605’ 4,613’ 4,371’ 4,379’ 8 8/19/23 Open
Bel F 4,629’ 4,641’ 4,392’ 4,404’ 12 8/19/23 Open
Bel F 4,682’ 4,687’ 4,448’ 4,453’ 5 8/19/23 Open
Bel F 4,704’ 4,714’ 4,470’ 4,480’ 10 8/19/23 Open
Bel F 4,731’ 4,743’ 4,497’ 4,509’ 12 8/19/23 Open
Bel F 4,765’ 4,775’ 4,531’ 4,541’ 10 8/19/23 Open
Bel F 4,797’ 4,811’ 4,563’ 4,577’ 14 8/19/23 Open
Bel F 4,855’ 4,861’ 4,610’ 4,616’ 6 8/19/23 Open
Bel G 4,945’ 4,954’ 4,709’ 4,718’ 9 8/18/23 Open
Bel G 4,979’ 4,989’ 4,743’ 4,753’ 10 8/18/23 Open
Bel G 5,005’ 5,017’ 4,769’ 4,781’ 12 8/18/23 Open
Bel G 5,027’ 5,037’ 4,791’ 4,801’ 10 8/18/23 Open
Bel G 5,069’ 5,075’ 4,832’ 4,838’ 6 8/18/23 Open
Bel G 5,091’ 5,109’ 4,854’ 4,872’ 18 8/17/23 Open
Bel G 5,143’ 5,155’ 4,905’ 4,917’ 12 8/17/23 Open
Bel G 5,181’ 5,187’ 4,943’ 4,949’ 6 8/17/23 Open
Bel G 5,204’ 5,210’ 4,966’ 4,972’ 6 8/17/23 Open
Bel G 5,217’ 5,222’ 4,979’ 4,984’ 5 8/17/23 Open
Bel G 5,237’ 5,243’ 4,999’ 5,005’ 6 8/17/23 Open
Bel H 5,366’ 5,372’ 5,136’ 5,142’ 6 8/15/23 Open
Bel H 5,398’ 5,418’ 5,159’ 5,179’ 20 8/15/23 Open
Bel H 5,493’ 5,499’ 5,253’ 5,259’ 6 8/15/23 Open
Bel H 5,512’ 5,518’ 5,272’ 5,278’ 6 8/15/23 Open
Bel H 5,530’ 5,535’ 5,290’ 5,295’ 5 8/14/23 Open
Bel H 5,555’ 5,561’ 5,314’ 5,320’ 6 8/14/23 Open
Bel H 5,610’ 5,630’ 5,371’ 5,390’ 20 8/14/23 Open
Bel H 5,637’ 5,643’ 5,396’ 5,402’ 6 8/14/23 Open
Bel H 5,660’ 5,672’ 5,418’ 5,430’ 12 8/13/23 Open
Bel H 5,672’ 5,697’ 5,430’ 5,454’ 25 8/13/23 Open
Bel H 5,957’ 5,982’ 5,712’ 5,736’ 25 8/13/23 Open
Bel I 6,318’ 6,332’ 6,069’ 6,083’ 14 8/2/23 Plugged
Bel J 6,635’ 6,648’ 6,385’ 6,398’ 13 8/2/23 Plugged
Bel J 6,911’ 6,921’ 6,658’ 6,668’ 10 8/2/23 Plugged
6-3/4”
hole
2
1
4
Updated by CAH 02-27-25
PROPOSED
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,086’ MD / TVD = 6,831’
TD = 7,199’ MD / TVD = 6,944’
RKB to GL = 19.9’
Bel I – Bel J
Bel F
Bel G
Bel H
Bel E
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface
3-1/2” TOC @ 2630’ (CBL 7-31-23)
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 2,785’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,597’ 7,156’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,605’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
Cactus CTF-ONE-CTL Hanger w/ 2G LH lift Thrd 4” type H BPV
1 174’ 2.830” 5.180” Baker ONYX-5RE TRSSSV
2 1,526’ 2.992” 4.780” Chemical Injection Mandrel
3 2,605’ 4.780” 6.370” Seal Stem (10’) w/ WEG, Liner hanger / LTP Assembly
4 6,268’ - 2.280” CIBP w/ 35’ cmt (TOC @ 6,233’ MD)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Top of Pool: 3,046 MD: 2824 TVD
Bel E1 ±4,066‘ ±4,078‘ ±3,836’ ±3,848’ ±12 TBD Proposed
Bel E1 ±4,089’ ±4,098‘ ±3,859’ ±3,868’ ±9 TBD Proposed
Bel E1 ±4,103’ ±4,111‘ ±3,873’ ±3,881’ ±8 TBD Proposed
Bel E2 ±4,127’ ±4,142’ ±3,897’ ±3,912’ ±15 TBD Proposed
Bel E3 ±4,209’ ±4,218‘ ±3,978’ ±3,987’ ±9 TBD Proposed
Bel E5 ±4,243’ ±4,256‘ ±4,012’ ±4,025’ ±13 TBD Proposed
Bel E5 ±4,321’ ±4,326’ ±4,090’ ±4,094’ ±5 TBD Proposed
Bel E6 ±4,347’ ±4,355’ ±4,115’ ±4,123’ ±8 TBD Proposed
Bel E6 ±4,360’ ±4,375’ ±4,128’ ±4,143’ ±15 TBD Proposed
Bel F 4,443’ 4,452’ 4,210’ 4,219’ 9 8/19/23 Open
Bel F 4,505’ 4,518’ 4,272’ 4,285’ 13 8/19/23 Open
Bel F 4,545’ 4,553’ 4,312’ 4,320’ 8 8/19/23 Open
Bel F 4,556’ 4,562’ 4,323’ 4,329’ 6 8/19/23 Open
Bel F 4,576’ 4,582’ 4,342’ 4,348’ 6 8/19/23 Open
Bel F 4,605’ 4,613’ 4,371’ 4,379’ 8 8/19/23 Open
Bel F 4,629’ 4,641’ 4,392’ 4,404’ 12 8/19/23 Open
Bel F 4,682’ 4,687’ 4,448’ 4,453’ 5 8/19/23 Open
Bel F 4,704’ 4,714’ 4,470’ 4,480’ 10 8/19/23 Open
Bel F 4,731’ 4,743’ 4,497’ 4,509’ 12 8/19/23 Open
Bel F 4,765’ 4,775’ 4,531’ 4,541’ 10 8/19/23 Open
Bel F 4,797’ 4,811’ 4,563’ 4,577’ 14 8/19/23 Open
Bel F 4,855’ 4,861’ 4,610’ 4,616’ 6 8/19/23 Open
Bel G 4,945’ 4,954’ 4,709’ 4,718’ 9 8/18/23 Open
Bel G 4,979’ 4,989’ 4,743’ 4,753’ 10 8/18/23 Open
Bel G 5,005’ 5,017’ 4,769’ 4,781’ 12 8/18/23 Open
Bel G 5,027’ 5,037’ 4,791’ 4,801’ 10 8/18/23 Open
Bel G 5,069’ 5,075’ 4,832’ 4,838’ 6 8/18/23 Open
Bel G 5,091’ 5,109’ 4,854’ 4,872’ 18 8/17/23 Open
Bel G 5,143’ 5,155’ 4,905’ 4,917’ 12 8/17/23 Open
Bel G 5,181’ 5,187’ 4,943’ 4,949’ 6 8/17/23 Open
Bel G 5,204’ 5,210’ 4,966’ 4,972’ 6 8/17/23 Open
Bel G 5,217’ 5,222’ 4,979’ 4,984’ 5 8/17/23 Open
Bel G 5,237’ 5,243’ 4,999’ 5,005’ 6 8/17/23 Open
Bel H 5,366’ 5,372’ 5,136’ 5,142’ 6 8/15/23 Open
Bel H 5,398’ 5,418’ 5,159’ 5,179’ 20 8/15/23 Open
Bel H 5,493’ 5,499’ 5,253’ 5,259’ 6 8/15/23 Open
Bel H 5,512’ 5,518’ 5,272’ 5,278’ 6 8/15/23 Open
(continued on following page)
6-3/4”
hole
2
1
4
Page 2 Updated by CAH 02-27-25
PROPOSED
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PERFORATION DETAIL (continued from previous page)
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel H 5,530’ 5,535’ 5,290’ 5,295’ 5 8/14/23 Open
Bel H 5,555’ 5,561’ 5,314’ 5,320’ 6 8/14/23 Open
Bel H 5,610’ 5,630’ 5,371’ 5,390’ 20 8/14/23 Open
Bel H 5,637’ 5,643’ 5,396’ 5,402’ 6 8/14/23 Open
Bel H 5,660’ 5,672’ 5,418’ 5,430’ 12 8/13/23 Open
Bel H 5,672’ 5,697’ 5,430’ 5,454’ 25 8/13/23 Open
Bel H 5,957’ 5,982’ 5,712’ 5,736’ 25 8/13/23 Open
Bel I 6,318’ 6,332’ 6,069’ 6,083’ 14 8/2/23 Plugged
Bel J 6,635’ 6,648’ 6,385’ 6,398’ 13 8/2/23 Plugged
Bel J 6,911’ 6,921’ 6,658’ 6,668’ 10 8/2/23 Plugged
1
McLellan, Bryan J (OGC)
From:Chad Helgeson <chelgeson@hilcorp.com>
Sent:Tuesday, March 18, 2025 2:32 PM
To:McLellan, Bryan J (OGC)
Cc:Noel Nocas; Donna Ambruz
Subject:RE: [EXTERNAL] BRU 211-35 (PTD 223-050) shallowest perf calcs
Thanks Bryan for the follow-up and clarity. See below for my response to your question.
1. I understand where you are coming from on using the deepest perfs as a base line: we need to provide you
with additional information of max buildup, which could be, BHP surveys with well shut-in, oƯset buildup
data, Open hole pressure tests (RFT’s), etc. I will move to the deepest open perfs on the future sundries or
will provide you more deƱnition around the max pressure if it is something diƯerent than deepest perfs
gradient.
2. It has bothered me for a while that we use 0.1 psi/ft for the gas gradient, however since the regulations use
that as a default, I was okay with it, but since we are putting a lot more eƯort into doing good engineering
on this section of the procedure for determining the shallowest allowable perfs, I wanted to start using real
numbers for actual gas gradient. The cook inlet gas is 99% methane and has a speciƱc gravity of 0.56 -
0.57, which is much lower than Prudhoe Gas (0.65) or N2 (0.97). I am calculating the actual gas gradient
based on depth of highest pressure interval. Most of the Cook Inlet gas should be between a 0.05 and 0.03
psi/ft gas gradient using our methane we produce from our Ʊelds depending on depth. I probably should
have called to discuss this change with you.
Please let me know if you do not agree with using the actual gas density for our calculations in the inlet, or if you
need additional information on the gas gravity.
Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, March 17, 2025 5:19 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: [EXTERNAL] BRU 211-35 (PTD 223-050) shallowest perf calcs
Chad,
Looking at the sundry application, I’m wondering about the calculation for lowest allowable perforation.
1. The MPSP is based on max BHP, which should be based on the deepest open perfs unless you have data to
suggest those perfs are lower pressure. In the calculation, you are using the deepest proposed add perf. I
think it needs to be based on the perfs at 5712’ TVD. I know it’s probably depleted somewhat, but without
data, just assume it’s not depleted as a worst case.
2. In the calculation for shallowest perf, you use 0.030 psi/ft for the gas gradient. What’s the basis for using
something other than 0.1 psi/ft?
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
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2
3. Even when I make the two changes above, your proposed perfs are still below the calculated shallowest
allowable. I can approve the sundry, but just want to get aligned on the methodology.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/12/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230912
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 18RD 50133205840100 222033 9/6/2023
YELLOW
JACKET GPT-PERF
BCU 18RD 50133205840100 222033 8/24/2023
YELLOW
JACKET PLUG
BCU 18RD 50133205840100 222033 8/28/2023
YELLOW
JACKET PLUG-PERF
BCU 18RD 50133205840100 222033 9/9/2023
YELLOW
JACKET PLU-GPT-PERF
BCU 18RD 50133205840100 222033 9/4/2023
YELLOW
JACKET SCBL
BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL
BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf
BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf
BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT
IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf
IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf
KTU 43-6XRD2 50133203280200 205117 9/4/2023
YELLOW
JACKET CALIPER
KU 42-12 50133206890000 220045 8/31/2023
YELLOW
JACKET GPT-PERF
KU 42-12 50133206890000 220045 8/20/2023
YELLOW
JACKET SCBL
MPU E-23 50029225700000 195094 8/18/2023
YELLOW
JACKET CBL-PLUG
MPU E-23 50029225700000 195094 8/20/2023
YELLOW
JACKET PERF
Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf
Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf
PBU L-240 50029237030000 221086 8/30/2023 READ IPROF
Please include current contact information if different from above.
T37983
T37983
T37983
T37983
T37983
T37984
T37984
T37984
T37985
T37986
T37987
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T37990
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T37992
9/13/2023
BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL
BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf
BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.09.13
10:28:30 -08'00'
By Grace Christianson at 9:37 am, Aug 25, 2023
Completed
8/2/2023
JSB
RBDMS JSB 083123
G
6901'
DSR-9/12/23
Drilling Manager
08/23/23
Monty M
Myers
Activity Date Ops Summary
6/25/2023 Tail Roll and Remove Catwalk, Boiler Module & 40' Connex F/ Location. Crane tie onto BOPE stack, Lift and remove studs from lower single gate & set in cradle
and secure. Remove BOPE stack F/ location. Remove Iron Roughneck F/ rig floor & secure in. carrier. Fold up all walkways on all walkways on all modules.
Scope in & lower doghouse into water tank. Shut down power & finish unplugging all electric lines & hydraulic lines. Remove all lights & handrails. Tail Roll Pit
module #3 & remove F/ location. Lay over gas buster with crane, Load on trailer with IR and remove F/ location. Tail Roll Pit Modules #2 & #1 and remove F/
location. Remove Jig, place on trailer and remove F/ location. Tail Roll Pump house bubble & Mud Pump #2 & remove F/ location. Tail Roll Doghouse/
Accumulator module, Top Drive HPU & Generator module & remove F/ location. Load matts on trailer and discard of felt and liner. Position cranes and attach
rigging to Derrick. Remove derrick F/ draworks skid & set on trailer. Secure before releasing rigging. Bring drilling line spool & secure with derrick. Start setting
Felt, Liner and Matts on BRU-211-35 on E Pad. Connect cranes to draworks skid. Loader pull skid away from subbase, Remove draworks skid, place on trailer &
move off of location. Connect cranes to subbase, remove from pony sub walls & set on matt boards. Load pony subs & take to E pad. Complete cleanup of
Matts, Liner & Felt on C pad. Set pony walls, Subbase and draworks skid at BRU 211-35. Spotted in pit mods 1,2 and 3. Set gen mod and both mud pump
mods. Rigged up water, hydraulics and air. Set derrick on headache rack and R/U mast raising cylinders. Raised roofs on all pits. Plugged in all electrical and
powered up rig. Set catwalk and R/U hyd. and function test. Raised V-door. Set boiler and 40' C-can. Raised derrick and pinned. R/U remaining water and
hydraulic lines. R/U steam lines. Pinned derrick board into place. Installed Centrifuge and raised degasser. Connected equalizer lines between pit modules.
6/26/2023 Install lower torque tube and turn buckles. Perform pre-scope derrick inspection. Scope up derrick and plug in crown lights. Bridle down. Rig down and moved
camp from C pad to E pad. R/U to pick up top drive. P/U top drive and hang from blocks. Check suction valves in tank 1 for repairs. Rigged up pason lines. Set
3rd party shacks and water upright. Install speed head, P/U and R/U torque bushing on torque tube. Hook you kelly hose and service loop to top drive. Make up
saver sub. R/U rig floor pipe handling equipment. Cont. connecting Pason around rig. Install blank flange on mess. kill valve. N/U spacer spool, T-spool, Knife
valve, Annular and 16" Vent line. Install bell nipple. R/U koomey lines check pre-charge on bottles and pressure up Accumulator. Fill pits with water and
checking all sensors. Function test shakers, agitators and mix pumps. Function test Annular and knife valve. Center torque tube over well. Installed chains on
Annular. Install mouse holes and load pipe racks on catwalk.
6/27/2023 Cont rig acceptance checklist, re-assemble hopper #1, purged air throughout the rig system, C/O power choke on choke manifold, installed valves on BOP
stack. Accepted rig at 08:00 on 6-27-23. racked, tallied then PU racked back 66 stands DP, received permit to drill from BLM at 14:05, gave AOGCC 48 hr
notice for diverter function test (6-29 at 10:00), updated BLM and Quadco Rep of same, started building first 100 bbl batch of spud mud. BLM Rep Allie
Schoessler waived witness of diverter function test via email at 16:28. CCI worked on main road by H pad, racked and tallied HWDP for PU and rack back. Ran
hardwire from office to service shacks for comms. PU racked back HWDP and jar stand. Drained stack and function tested diverter. Cont building spud mud 403
bbls total, rebuilt wash pipe, general housekeeping and maintenance, change oil on loader. Continue performing general housekeeping and maintenance, work
on containment for mud dock area clean and organize 40' connex.
6/28/2023 Ran roller compactor on offside of rig to compact wet sand for CCI truck and loader traffic, strapped surface casing on H pad, de-watered waste cell #8 for
surface cuttings, AOGCC Rep Jim Regg waived witness of diverter function test at 09:03, called out Quadco Rep for noon flight to Beluga. Performed diverter
function test, measured vent line and nearest ignition source, set signs and blockades, functioned flow and PVT alarms, performed draw down of koomey unit.
MU 9 7/8" HDBS PDC jetted w/5 x 14's to 6 3/4" motor with 1.5 bend, MU DM collar, scribe with an RFO of 50.52 while waiting on arrival of Quadco Rep.
Checked and tightened hyd fittings on catwalk. MU EWR-M5 and TM collar, plugged in and uploaded MWD tools. Quadco Rep on location at 13:00 and tested
all audio/visual gas alarms. Filled stack with spud mud through fill up line and checked for leaks (ok). Attempted to MU stand HWDP but damaged saver sub
and top grabber plates (grabber partially closed, saver sub set down on grabber plates/dies while rotating). C/O saver sub and top pates, MU stand HWDP and
topdrive, attempted to circ but pressured up. Trouble shot and eventually found hyd IBOP on topdrive was closed, indicator light wasn't working. Functioned
valve couple times, indicator light working, valve open. Shallow pulse tested tools, washed down and spudded well at 134', at 14:45. Drilled two stands HWDP
down to 201', racked back 2 stands HWDP, PU two singles NM flex DC's, re-ran HWDP and drilled ahead from 201' to 384'. Adjusted topdrive "T" bar and ran
jar stand. Cont drilling 9 7/8" surface hole from 384' to 1132', sliding wob 0-5K, 396 gpm-886 psi, 119 psi diff, 90 to 600 ft/hr ROP. Rot wob 0-10K, 370 gpm-
1188 psi, 35 rpm-3051 ft/lbs on bott torque, 55 to 200 ft/hr ROP. MW 8.9/vis 227, ECD's 10 ppg, BGG 0. Sent 72 hr notice to BLM for surface casing/cement.
Continue Drilling 9 7/8'' Surface Hole f/ 1132' t/ 1441' 420 gpm 1150 psi SPP, 40 rpm 4k tq on bottom, MW 8.95 ppg ECD 9.97 ppg, WOB 2-5, 51k PUW 42k
SOW 46k ROT, 200 fph ROP, Distance to plan 25.36' 21.87' High 12.84' Right. Circulate bottoms up, flow check well static,. POOH on elevators f/ 1441' t/ 345'
work through tight spot @ 1336' 30k over pull wiped clean x3 no other hole issues. Service rig and top drive, clean suction screens on pumps 25% packed off,
check pulsation dampeners, grease crown and draw works. RIH f/ 345' t/ 759' No hole issues.
6/29/2023 Cont TIH on elevators from 759', down wt 30K. At 1340' set down 10K twice. MU topdrive, filled pipe, washed and reamed stand down to 1374', worked stand
with no pump/rotary and was clean. Cont to ease in hole washing last stand to bottom at 1441'. Made hook, pumped 20 bbl nutplug sweep down and out the bit.
Resumed drilling 9 7/8" surface hole from 1441' to 1803', rot wob 1-2K, 425 gpm-1158 psi, 40 rpm-4800 to 5300 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob
1-2K, 427 gpm-1270 psi, 59 psi diff, 100 to 200 ft/hr ROP. MW 8.9/vis 126, ECD's at 9.8 ppf, BGG 1 unit, max gas 77 units. Sweep was back on time with no
increase in cuttings. At 1712' increased topdrive RPM to 60 with 5990 to 6000 ft/lbs on bott torque. Cont drilling from 1803' to 2266', rot wob 1-2K, 554 gpm-
2029 psi, 60 rpm-6600 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 1-2K, 495 gpm-1717 psi, 95 psi diff, 200 ft/hr ROP. MW 9.0/vis 230, ECD's at 9.8 ppg,
BGG 1 unit, max gas 17 units. Updated BLM and AOGCC of casing run and cementing. Continue Drilling 9 7/8'' Surface hole f/ 2266' t/ 2795' TD 570 gpm 2163
psi SPP 60 rpm 6k tq on bottom MW 9.1 ppg ECD 9.74 ppg, 72k PUW 50k SOW 58k ROT, Distance f/ Plan 8.84' 5.22' High 7.14' Right. Circulate bottoms up,
obtain survey and flow check well static. Make wiper trip f/ 2795' t/ 698' no hole issues. Service rig and top drive, clean suction screens on pumps, grease and
inspect draw works. RIH f/ 698' t/ 2405' with no issues.
18.5
n (LAT/LONG):
evation (RKB):
50-283-20189-00-00API #:
Well Name:
Field:
County/State:
BRU 211-35
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00091 BRU 211-35 Drilling
Spud Date:
Cont rig acceptance checklist
g
Cont drilling 9 7/8" surface hole from 384' to 1132',
pp q
Continue Drilling 9 7/8'' Surface Hole f/ 1132' t/ 1441'
qggppp
Updated BLM and AOGCC of casing run and cementing. Continue Drilling 9 7/8'' Surface hole f/ 2266' t/ 2795'
6/30/2023 Cont TIH on elevators from 2405', down wt 42K, MU topdrive at 2737' filled pipe, washed to bottom at 2795' with no issues. Pumped 20 bbl hi-vis nutplug sweep
around at 568 gpm-2282 psi, 80 rpm-8973 ft/lbs off bott torque. Sweep back on time with 20% increase in cuttings. Circulated and additional bottoms up thinning
mud for casing run and cementing. Flow check = static. POOH on elevators from 2795' to BHA at 700' with no issue. Up wt 76K. Updated BLM and AOGCC via
email on upcoming casing run, cementing and upcoming BOP test. Racked back HWDP, LD jars and single, racked 3 more stands HWDP, LD NM flex DCs.
Downloaded MWD data, removed pulser, LD remainder smart tools and motor. Bit graded 2-4-BT-A-X-I-ER-TD. Cleared and cleaned rig floor/catwalk, PU and
MU landing joint on hanger with wellhead Reps. Dummy ran hanger and LD same. Leveled up sub base, staged centralizers and casing tongs on catwalk.
Offloaded excess spud mud from pits. RU casing tongs and elevators, RU fill up line, staged centralizers and drive sub on rig floor, held PJSM. Loaded pipe
rack with casing. Cleaned pill pit and trip tank for blackwater use. Inspected and MU shoe track, BakerLok and top filling each joint, stroked pipe and ensured
float equipment working (ok). Cont PU single in hole with 7 5/8" TXP BTC, 29.7# L-80 casing, torqued to 17,740 ft/lbs, centralized every other joint up to 300', top
filling on the fly,. topping off every tenth joint, from 127' to 2744', M/U hanger and landing jt, Land on hanger. M/U circulating equipment, stage pumps to 6 bpm
54 psi, R/D casing equipment send off floor, spot in cementers & R/U, Load plugs and M/U cement head circulate while holding pre job. Halliburton loaded lines
with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 995 low 3100 high, good tests. Halliburton pumped 60 bbls 10.5 ppg Spacer at 5
bpm and shut down. Halliburton dropped bottom plug and pumped 165 bbls (390 sx) 12 ppg Class A lead cement at 6 bpm. followed by 37 bbls (169 sx) 15.8
ppg Class A tail cement at 5 bpm. Halliburton dropped top plug, then displaced with 121 bbls 9.1 ppg Spud Mud at 6 bpm. Slowed to 2 bpm with 10 bbl to go.
Did bump the plug 121 bbls into displacement (calculated 123.9 bbls), held 1200 psi (FCP of 740 psi) for 3 min. bled off and floats held. Bled back .75 bbls to
truck. Had 60 bbls Spacer returns to surface and 85 bbls lead cement to surface. Lost 0 bbls during displacement. Reciprocated string 2 x per minute throughout
the job. Up wt 95 K Decreased to 65 K, dwn wt 50 K at time of landing hanger. CIP at 02:49hr. 7/1/23. Blow down and R/D Halliburton Cementers. Back out
landing jt, flush stack with stack washer and drain stack with black water flush annular and function multiple times, clean up under shakers and possum belly,
suck out and clean out cellar. N/D Diverter Vent line and Stack.
7/1/2023 Cont tear out diverter vent line, knife, annular and "T". Pulled adaptor flange with spacer spool. Pressured washed each component as they are removed. Cont
haul off spud mud and top washing in pits. Verified wellhead orientation with Production. Installed slip on wellhead and tested tubing head seals at 5000 psi for
15 min. Ran in drive screws and torqued to 650 ft/lbs. Set wear ring and run tool in wellhead, installed 2' spacer spool, folded back beaver slide, transferred BOP
stack to bridge cranes from cradle with CCI crane. Set BOP stack, installed drip pan, hammered up flange bolts. Quadco Rep on location at 10:45 and tested all.
audio/visual gas alarms. Installed hard line off choke side mud cross to catwalk, installed kill line. Cont cleaning tank bottoms in pits. Installed flow riser and flow
line. Installed koomey lines. Power up koomey unit. Pulled wear ring/run tool, set test plug, flooded surface lines, stack and choke manifold. Functioned valves
and purged air. Transported 3% KCL mud from CCI tank farm to rig. Attempt shell test w/ 4.5'' test jt. Double ball valve IBOP on topdrive and bleeder valves on
test manifold leaking, changed out valves and double ball IBOP on topdrive. Tested annular at 250 low f/5 min and 2500 high f/10 min, swap to upper ram test.
Leak on ram shaft seal, bled down koomey and drained stack, opened ram door and changed shaft seals on ODS upper ram door, retest system to 3500 psi
ODS upper ram shaft seal holding. but ODS blind ram shaft seal leaking, close lower rams and test to 250 low f/5 min and 3500 high f/10 min good test, test
auto and manual IBOP valves t/ 250 low for 5 min and 3500 high f/10 min good tests. Mobilize BOP ram shaft seal parts to plane, to be transported to beluga,
bled down koomey, opened ODS blind ram door and dis-assemble ram shaft for seal kit replacement.
7/2/2023 Dis-assembled ODS blind ram shaft and piston for seal change while waiting on delivery of seal kit from Kenai. Cleaned, inspected and re-assembled ram shaft
and piston, buttoned up door, functioned blinds, flooded stack and functioned blinds again to clear air from cavities,. installed test joint and functioned
upper/lower rams and annular to clear air from cavities. Shell tested BOP stack at 250 low for 5 min, 3500 high for 10 min, no issues. Tested all BOPE at 250
low/3500 high with no issues, 5 min low, 10 min high. Performed drawdown test, tested blinds then auto/manual chokes on choke manifold. Allie Schoessler with
BLM waived witness on 6-30-23 at 09:12. Jim Regg with AOGCC waived witness on 7-1-23 at 14:04. Drained stack, pulled test plug, set 9" ID wear ring, flooded
stack, purged air. Pumped 67.5 gallons water with test pump to achieve 3520 psi on 7 5/8" surface casing. Held 30 min on chart, lost 17 psi over 30 min, good
test. Staged BHA #2 on catwalk. Blew down choke manifold and surface lines, RD test equipment. MU GTD54DM PDC and motor with 1.5 bend, MU Sperry
smart tools, plugged in and uploaded MWD, shallow pulse tested, load sources RIH t/ 182'. RIH f/ 182' t/ 2693' P/U 64 jts of DP, set down kelly up and wash
down t/ plugs @ 2696' Drill float equipment and cement t/ 2795', Drill 20' of new hole t/ 2815' 3k WOB 35 rpm 5800 tq 225 gpm 1300 psi SPP. Displace spud
mud w/ 6 % KCL Polymer mud. R/U to perform FIT.
7/3/2023 Racked back stand, MU headpin on stump, flooded surface line and choke manifold, RU test pump on kill line and drill string, closed upper rams, pumped 13.8
gallons to achieve 655 psi to give us 13.9 ppg EMW on LOT. Sent data to Drilling Engineer and approved to drill ahead. RD test equipment, opened upper rams
and vacd out choke manifold, lined up kill/choke valves for drilling. Serviced rig and topdrive. Made hook and resumed drilling 6 3/4" hole from 2815 to 2984'.
Rot wob 7K, 217 gpm-1425 psi, 60 rpm-5700 ft/lbs on bott torque, 27 to 120 ft/hr ROP. Sliding wob 1-2K, 226 gpm-1263 psi, 134 psi diff, 160 ft/hr ROP. MW
9.0/vis 54, ECD's at 9.9 ppg, BGG 14, max gas 38 units. Cont drilling from 2984' to 3338', rot wob 1-2K, 260 gpm-1731 psi, 60 rpm-6190 ft/lbs on bott torque,
120 ft/hr ROP. Sliding wob 1-2K, 264 gpm-1444 psi, 85 psi diff, 120 ft/hr ROP. MW 9.1/vis 56, ECD's 10.1, BGG 13, max gas 271 units. Mad passed longer slide
intervals. Cont drilling from 3338' to 3773' 252 gpm 1470 psi SPP, 60 rpm 7100 tq on bottom, 4-7k WOB Max gas 637 units, PUW 80k SOW 54k ROT 64k ECD
10.05ppg MW 9.1 ppg. Cont drilling from 3773' t/ 4019' 250 gpm 1455 psi SPP 60 RPM 7600 tq on bottom 3-6k WOB, PUW 82k SOW 54k ROT 65k, MW 9.1
ppg ECD 10.2, Distance to plan 8.87' 8.45' High 2.71' Left. Circulate bottoms up, Obtain survey and SPR's, Flow check well static slight loss. POOH on
elevators f/ 4019' t/ 2096' no hole issues pulled clean through shoe,.
7/4/2023 Cont POOH from 2096' to 740', up wt 44K. RU Sperry GeoSpan unit in cellar. Racked back HWDP, jars and NM flex DC's, held PJSM and removed sources,
plugged in and down loaded MWD data. L/D TM and PWD collars, PU GeoTap and TM collars, MU topdrive, plugged in and uploaded MWD data, shallow pulse
tested, held PJSM and loaded sources. RIH with NM flex DC's, HWDP and jars to 755'. *During upload of MWD, GeoLog Rep slipped on stairs coming down off
pits, and felt he injured his bicep muscle, sent Rep to CCI camp to see medic and made notifications to town. Rep came back cleared to resume working. Cont
TIH on DP from 755' to 2787', MU topdrive and filled pipe. Cont to trip in open hole from 2787' to 3353', down wt 48K. MU topdrive and filled pipe. Madd passed
from 3350' to 3400' at 200 ft/hr. 227 gpm-1163 psi, 60 rpm-6700 ft/lbs off bott torque. Had a max of 193 units gas at bottoms up. Oriented string, worked out
torque then parked GeoTap probe at 1st station depth of 3283'. Cont. collecting data w/ Geo-Tap. BHA from stations #1 through station #8 F/3283'-T/3440'.
GPM-260 SPP-1307 psi MW-9.1 ppg ECD-9.9 ppg Max gas -12 units. Pressure tested back up IBOP for TD off line (ok), and worked on housekeeping and
cleaning rig. Crew change, held PTSM. Cont. collecting data w/ Geo-Tap tool from station #8. Working on current station # 14 @ 3755'. P/U-82K S/O-56K GPM-
250 SPP-1318 psi MW-9.1 ppg ECD-9.9 ppg Max gas- 7 units. Changed oil and filters on draw works motor, cont. with. cleaning and housekeeping on rig.
7/5/2023 Cont GeoTap formation sampling from station #14 at 3650' to station #26 at 3887' with no issues. 253 gpm-1351 psi. Washed and reamed 29' to bottom,
pumped a 20 bbl hi-vis nutplug sweep around at 250 gpm-1421 psi, 60 rpm-7769 ft/lbs off bott torque. Had 50% increase in cuttings at bottoms up followed with
a 20% increase with sweep to surface. Sweep back on time. Obtained SPR's with 9.0 MW and flow check = static. POOH from 4014' to 2735' (inside casing
shoe). Monitor well, blow down topdrive and mud line, disconnect Sperry GeoSpan unit from mud and flow lines, blow down same. Cont POOH from 2735' to
BHA at 755'. Racked back NM flex DC's, HWDP and jars, removed sources, downloaded MWD data, L/D Geo-Tap tools and changed out TM collar. Cal hole fill -
28.28 bbls Act - 30.1 bbls Diff- 1.82 bbls over. Verified off set - XXXX. P/U PWD, new TM collar. Started uploading MWD data. Racked & tallied 18 jts of 4.5" DP
on catwalk. Crew change, held PTSM. Finished uploading MWD data. Performed shallow pulse test on MWD tools (ok). P/U and ran in remainder of BHA #4
T/715'. P/U and singled in the hole w/ 18 jts of 4.5" DP on top of BHA #4 off the walk. Cont. RIH out of derrick T/1514'. Filled pipe. Resumed RIH out of the
derrick at 30 fpm F/1514' to current depth of 2631'.
g j
Halliburton pumped 60 bbls 10.5 ppg Spacer at 5pggppppg p
bpm and shut down. Halliburton dropped bottom plug and pumped 165 bbls (390 sx) 12 ppg Class A lead cement at 6 bpm. followed by 37 bbls (169 sx) 15.8g()g y()
ppg Class A tail cement at 5 bpm. Halliburton dropped top plug, then displaced with 121 bbls 9.1 ppg Spud Mud at 6 bpm. Slowed to 2 bpm with 10 bbl to go.ppg p pp p p g p ppg p p
Did bump the plug 121 bbls into displacement (calculated 123.9 bbls), held 1200 psi (FCP of 740 psi) for 3 min. bled off and floats held.
p
Updated BLM and AOGCC viagg
email on upcoming casing run, cementing and upcoming BOP test
13.9 ppg EMW on LOT
CIP at 02:49hr.
7/6/2023 Cont ease in hole from 2631' to 2809' at 20 to 30 ft/min or we are pushing mud away. MU topdrive and filled pipe. Cont ease in open hole from 2809', down wt
44K, to 3995' and MU topdrive. Filled pipe, increased rate to 180 gpm-947 psi, 40 rpm-7000 ft/lbs off bott torque, washed and reamed to bottom at 4018'. CBU
one time with 14% flow at 180 gpm, max gas 135 units at bottoms up, obtained SPR's with new BHA. Resumed drilling 6 3/4" hole from 4018' to 4127'. Rot wob
4-5K, 179 gpm-928 psi, 60 rpm-7000 ft/lbs on bott torque, 15 to 60 ft/hr ROP, MW 9.0/vis 64, ECD's 9.9 to 10.0 ppg, BGG 4 units, max gas 1214 units. At 4118'
with stand drilled down, went to backream prior to connection, pulled up hole 10' and had a sudden pump pressure spike to 1824 psi, rotating torqued spiked
from 7457 to 13900 ft/lbs, flow dropped from 15% to 1%. Stopped moving string, reduced pump rate to 150 gpm,. flow came back but lost 30 bbls over 15
minutes while trying to cont backream for connection, up wt 86K, dwn wt 58K. Was able to backream entire stand with no further issue so made connection.
Cont drilling from 4127' to 4180'. Rot wob 2-4K, 178 gpm-1057 psi, 60 rpm-7373 ft/lbs on bott torque, 50 ft/hr ROP in attempt to reduce or maintain ECD's at 9.9
to 10.0 ppg. MW 9.1/vis 58, ECD's at 9.9 ppg, BGG 52 units, max gas 458 units. At 4180' with stand drilled down, attempted to backream for connection, pulled
up hole 3' and diff spiked from 56 to 383 psi, pump pressure spiked from 962 to 1289 psi, rot torque spiked from 7284 to 8135 ft/lbs, flow did not drop off.
Stopped string movement, parameters. returned to normal. Was then able to backream and make connection. Drilled from 4180' to 4236' md/4005' tvd, Rot wob
3K, 180 gpm-1091 psi, 80 rpm-7800 ft/lbs on bott torque, 50 ft/hr ROP and had a sudden flow drop from 15% to 7% after drilling through a small hard. streak.
Lost 40 bbls over 15 minutes. Also reduced pump rate to 150 gpm-788 psi, flow up and down from 6 to 11%. Flow came back so increased to 170 gpm-1036 psi
and drilled stand down to 4242' with no further flow issue. Attempted to backream stand for connection. and immediately had pump pressure spikes, some slight
torque and diff spikes, flow dropped to 0% while pulling up hole. Could stop string, slack off 2' and pump pressure dropped, flow returned to normal. Made
numerous attempts at backreaming with same results. Attempted to pull up hole with no rotation, low rotation, same results, pump pressure spikes and loss of
flow unless slack off a couple feet. Notified Drilling Engineer, appears we may have wiper rubber over lower BHA, saw no ECD spikes at all. Decision made to
pull up hole above 4018' then possibly back to bottom and check for packing off again. Never had any over pull or significant increase in rotary torque, does not
appear to be differential sticking, just pack off and loss of flow. CBU at 4242' md/4009' tvd, 170 gpm-861 psi, 80 rpm-7355 ft/lbs off bott torque, 11% flow. Cont
to circ until gas dropped from 414 to 147 units. Attempted to pull on elevators, up wt 88K, but saw immediate swabbing, MU topdrive and attempted to pump
OOH with no rotatary, seeing pressure spikes and loss of returns, started rotating again seeing pressure spikes and loss of returns unless slack off +/- 2'.
Started backreaming working up hole in 10' to 15' increments pulling fast, until pump pressure would increase and flow drop off unless we slacked off 2' and
stabilized parameters, from 4236' to 4000'. At which time we could pull slow and steady seeing no packoff or loss of returns (old hole),. 157 gpm-721 psi, 40 rpm-
6200 ft/lbs torque, 10 to 11% flow, pulling at 25 ft/min. Decision made to pump OOH and check for wiper rubber on BHA. Cont to pump OOH from 4000' to
2803'. CBU at 174 gpm-778 psi, 40 rpm-5000 ft/lbs off bott torque, 14% flow, BGG 9 units. At bottoms up shut down and flow checked (static). From 09:00 to
18:30 we have lost total 196.9 bbls. Pumped OOH inside 7-5/8" casing due to swabbing. F/2803-T/BHA #4. Racked back HWDP, jar std, flex collars, HES MWD
tools. Inspected BHA on the way OOH, noticed minor scaring on the ADR collar. Brought bit through the table. All but one junk slot on the bit was. packed off. Bit
graded 1-1-WT-A-X-1-WT-BHA. 1/32 under gauge. Crew change, held PTSM. Serviced rig- Greased crown, blocks, TD, IR, wash pipe, DWKS, brake linkage,
and drive shaft. Cleaned suction screens on MP's. Checked pulsation dampeners on MP's. Inspected saver sub on TD (ok). Changed out MP #2 throttle control
on. drillers consul. Drained, cleaned, and inspected TT vertical hole fill pump. Discussed bit options with drilling engineer. Decision was made to RR bit. BHA #5 -
M/U 6.75" PDC bit, 1.5 motor. Verified off set (94.9). M/U MWD tools. Performed shallow pulse test (ok). RIH w/ remainder of BHA #5. Cont. RIH F/715' to
current depth of 1640'. Distance to well plan: 4.37' 4.12' High 1.47' Left.
7/7/2023 Cont TIH on elevators from 1640' to 2880' at 20 to 30 ft/min, MU topdrive and filled pipe at 2880', cont TIH from 2880' to 3995' at 20 to 30 ft/min with no issues.
MU topdrive and filled pipe, washed and reamed down to 4018' at 160 gpm-751 psi, 40 rpm-6868 ft/lbs torque. At 4018' pumped a 20 bbl low-vis nutplug condet
sweep around, staging up to 180 gpm-928 psi, 40 rpm-6400 ft/lbs torque, 14 to 15% flow, 90 units max gas at bottoms up, sweep on time with no increase in
cuttings. Washed and reamed down to 4055'. Washed and reamed from 4055' to bottom at 4242'. 180 gpm-924 psi, 40 rpm-6030 ft/lbs torque, 15% flow. On
each stand backreamed after washing down to mimic drill down/backream from previous day with no issue. At 4232' we did get into some sort of fill or tight hole.
and saw pressure spike from 951 to 1674 psi, PU and pressure dropped off, no loss in return flow. Cont to inch down from 4232' to 4242', went to backream and
had an immediate spike in pump pressure, stopped pulling, pressure dropped off, flow steady, then able to backream. Cont drilling 6 3/4" hole from 4242' to
4427'. Sliding wob 4K, 180 gpm-1072 psi, 168 psi diff, 8 to 50 ft/hr ROP. Rot wob 1 to 5K, 180 gpm-1009 to 1314 psi, 65 rpm-7730 ftlbs on bott torque, 46 to 50
ft/hr ROP. MW 9.1/vis 56, ECD's at 9.9 ppg, BGG 19, max gas 374 units. ROP of 50 ft/hr has been keeping ECD's at or below 10.0 ppg with 9.1 ppg mud.
Drilling with 180 gpm, upstroke on backream 180 gpm, down stroke at 160 gpm. Changed out trip tank pump and test ran same. Lost 16 bbls while drilling (noon
to 18:00). Cont. drilling 6.75" production hole F/4427'-T/4675'. P/U-85K S/O-57K ROT-69K GPM-180 SPP-1010 psi TQ-7.9K RPM-60 Flow-15% ROP-50 WOB-
2/6K Diff-95 psi MW-9.15 ppg ECD-10.16 ppg Max gas -293 units. Crew change, held PTSM. Cont. drilling 6.75" production hole F/4675' to current depth of
4825'. P/U-91K S/O-58K ROT-71K GPM-180 SPP-1137 psi TQ-8.2K RPM-60 Flow-14% ROP-50 WOB-2/6K Diff-160 psi MW-9.1 ppg ECD-10.2 ppg Max gas -
115 units. Distance to well plan: 3.91' .03' Low 3.91' Left.
7/8/2023 Cont drilling 6 3/4" hole from 4825' to 5034', Rot wob 1-6K, 180 gpm-1102 psi, 60 rpm-8060 ft/lbs on bott torque, 50 ft/hr ROP, Sliding wob 1K, 183 gpm-1179
psi, 197 psi diff, 45 ft/hr ROP. MW 9.0/vis 55, ECD's 10.2 ppg, BGG 68, max gas 382 units. Cont drilling 6 3/4" hole from 5034' to 5206', Sliding wob 1K, 183
gpm-1122 psi, 140 psi diff, 40 ft/hr ROP. Rot wob 2-6K, 182 gpm-1274 psi, 60 rpm-8748 ft/lbs on bott torque, 7-50 ft/hr ROP. MW 9.1/vis 54, ECD's 10.2, BGG
71, max gas 198 units. Cont. drilling 6.75" production hole F/5206'-T/5322'. P/U-97K S/O-74K ROT-60K GPM-180 SPP-1245 psi TQ-8.2K RPM-60 Flow-14%
ROP-50 WOB-2/6.5K Diff-194 psi MW-9.15 ppg ECD-10.19 ppg Max gas -238 units. Obtained new SPR's @ 5260' MD. Off line strapped & tallied 3.5" 9.2# L-80
Wedge 563 liner and tie back strings on H pad. Crew change, held PTSM. Cont. drilling 6.75" production hole F/5322' to current depth of 5439'. P/U-100K S/O-
60K ROT-78K GPM-180 SPP-1280 psi TQ-8.4K RPM-60 Flow-14% ROP-50 WOB-2/6.5K Diff-116 psi MW-9.1 ppg ECD-10.2 ppg Max gas -132 units. Distance
to well plan: 7.13' .56' Low 7.10' Left. Lost 21 bbls over the last 24 hrs.
7/9/2023 Cont drilling 6 3/4" hole from 5439' to 5547', Rot wob4-6K, 180 gpm-1352 psi, 60 rpm-8582 ft/lbs on bott torque, 13 to 50 ft/hr ROP. Sliding wob 1K, 179 gpm-
1321 psi, 119 psi diff, 46 ft/hr ROP. MW 9.0/vis 60, ECD's at 10.2 ppg, BGG 30 units, max gas 490 units. Cont drilling from 5547' to 5720', Rot wob 2 to 6K, 180
gpm-1288 psi, 60 rpm-9545 ft/lbs on bott torque, 10 to 50 ft/hr ROP. MW 9.1/vis 53, ECD's at 10.3 ppg, BGG 40 units, max gas 614 units. CCI cont working on
road to Lewis River. CBU twice at 180 gpm-1169 psi, 60 rpm-9300 ft/lbs off bott torque. Obtained on bottom survey, SPR's and flow check was static. Pumped
OOH F/5722'-T/3985' @ 15 fpm. Had minor pressure increase through out trip F/200 psi- T/500 psi. P/U-100K S/O-60K GPM-160 SPP-975 psi MW-9.15 ECD-
10.17 ppg Max gas - 95 units. Pumped 20 bbl Low-Vis sweep @ 3958' w/ walnut and condet to scrub bit & BHA. P/U-82K S/O-65K ROT-58K GPM-180 SPP-949
psi RPM-80 TQ-7.8K Flow-16% MW-9.15 ppg ECD-10.3 ppg Max gas - 68 units. Crew change, held PTSM and weekly safety meeting w/ rig crew. Finished
pumping sweep OOH. Had 75% increase in cuttings at BU. Sweep came back on time w/ a 40% increase in cuttings. Circ. an additional BU waiting on shakers
to clean up. After sweep ECD's dropped to 9.9 ppg. Flow checked well (static). POOH on elevators F/3958'-T/2687' w/ no issues. P/U-56K S/O-41K. Lined up TT
on hole to monitor hole. Calculated hole fill during OH trip-10.5 bbls Act- 9.03 bbls Diff- 1.47 bbls over. Rig Service- Greased crown, blocks, TD, IR, wash pipe,
DWKS, brake linkage, and drive shaft. Cleanout both MP suction screens and checked MP pulsation dampeners. Changed out DWKS transmission shifter on
drillers consul. Loss rate on TT = 2.8 bph. POOH F/2687'-T/BHA #5. Currently L/D BHA #5. Distance to well plan: 5.85' 1.69' High 5.60' Left.
gg
Cont. drilling 6.75" production hole F/4427'-T/4675'.
Cont drilling 6 3/4" hole from 5439' to 5547
7/10/2023 Racked back 3 stands HWDP and NM flex DC's, plugged in and downloaded MWD. Troubleshot draw works transmission shifting issue during download, L/D
remainder smart tools, checked motor for end play (tight), bit graded a 2-1. Monitored well on trip tank while cleaning and clearing rig floor/catwalk, staged next
BHA on catwalk. Loss rate at .66 bph on trip tank. Closed blinds to C/O trip tank pump. Removed drawworks transmission shifter from doghouse console, tore
down and cleaned out, removed shifting actuator from transmission, tore down and cleaned out, blew through all air lines pertaining to shifting, re-assembled
everything but no change, only shifts into 1st and 2nd gear. Called for spare actuator from Rig 169 and set up to transport on CCI's changeout flight, Replaced
trip tank pump and flow line flow sensor. PU new 4 3/4" motor with 1.5 bend, MU 6 3/4" GTD54D PDC, MU DM and PCG collars, scribed for an RFO of 145.5,
MU ADR, ALD, CTN, PWD and TM collars, MU topdrive, plugged in and uploaded tools, shallow pulse tested, PJSM and loaded sources. RIH 3 stands HWDP,
PU new jars and single HWDP, ran remainder HWDP from derrick to 740.57'. Cont TIH at 20 to 30 ft/min on 4 1/2" DP to 1402', MU topdrive and filled pipe. RIH
to 2900'. Filled pipe and CBU to freshen up mud in hole as we've been pushing a little mud away at 173 gpm-764 psi, 40 rpm-5247 ft/lbs off bott torque, 15%
flow, max gas of 615 units. Cont. RIOH F/2900'-T/4015' at 15-20 fpm w/ no issues. Cal pipe displacement for the trip - 72.04 bbls Act- 43.86 bbls Diff - 28.1 bbls
lost to hole. P/U-64K S/O-48K. Started Madd pass logging as per Sperry F/4015'-T/4350' at 200 fph. P/U-80K S/O-58K ROT-69K GPM-160 SPP-744 psi RPM-
50 TQ-5.6K MW-9.15 ppg ECD-9.9 ppg Max gas -1329 units. Crew change, held PTSM. Cont. Madd pass logging as per Sperry F/4350' to current depth of
5128'. P/U-90K S/O-64K ROT-74K GPM-160 SPP-826 psi RPM-50 TQ-6.5K MW-9.15 ppg ECD-9.9 ppg Max gas -124 units.
7/11/2023 Cont. Madd Pass logging F/ 5128' T/ 5182' @ 160 GPM, 760 psi SPP, 50 RPM 8200 ft/ lbs Tq. At 5150' gas rose F/ 24 units T/ +/- 5000 units over 5 minutes,
Flow increased F/ 14% T/ 39%. Complete Madd Pass down T/ 5182' to get DP positioned for shut in. Notified CCI to not operate any equipment and started
increasing MW F/ 9.1 ppg T/ 9.3 ppg going down hole with Vacuum Degasser on. Cont. circulating @ 160 GPM, 760 psi SPP, 50 RPM 8200 ft/ lbs TQ. Gas
started dropping after 20 minutes, Gained total of 9 BBLs. Cont. weight up surface volume T/ 9.3 ppg At Bottoms up gas down T/ 742 units and work string down
T/ 5189'. Cont. Madd Pass logging F/ 5189' T/ 5309' maintaining 9.3 ppg MW in and out. 160 GPM, 822 psi SPP, 50 RPM, 7400 ft/ lbs off bottom TQ. 14% flow
and ROP @ 200FPH. Gas up F/ 600 units T/ 2390 units @ 5309'. Cont. circulating @ 160 GPM, 760 psi SPP, 50 RPM, 7400 ft/ lbs TQ. Circulate gas out and
dust MW up T/ 9.4ppg. Cont. Madd Pass logging F/ 5309' T/ 5438' maintaining 9.4 ppg MW in and out. 160 GPM, 780 psi SPP, 50 RPM, 8000 ft/ lbs off bottom
TQ. 14% flow and ROP @ 200FPH. Gas rising F/ 283 units T/ 1494 units. Position drill string across stack and circulate gas units back down T/ 135 units. 160
GPM 800 psi SPP, 50 RPM with TQ at 7742 ft/ lbs. Monitor Well with no flow. Cont. Madd Pass logging F/ 5438' T/ 5617' maintaining 9.4 ppg MW in and out.
160 GPM, 820 psi SPP, 50 RPM, 8277 ft/ lbs off bottom TQ. 14% flow and ROP @ 200FPH. Gas rising F/ 227 units T/ 2358 units. Circulate gas units back down
at 5617' T/ 350 units. 160 GPM 800 psi SPP, 50 RPM with TQ at 8070 ft/ lbs. Monitor Well with no flow. Cont. Madd Pass logging F/ 5617' T/ 5722' maintaining
9.4 ppg MW in and out. 160 GPM, 900 psi SPP, 50 RPM, 8258 ft/ lbs off bottom TQ. 14% flow and ROP @ 200FPH. Pump 20 BBLs Lo-Vis Con Det/ Nut Plug
sweep STS @ 160 GPM, 830 psi. SPP, 8525 ft/ lbs TQ. Sweep came back on time with no increase in cuttings. Obtain new SPRs @ 5715' MD 5470' TVD
MP#1 21 SPM 289 psi. MP#2 21 SPM 293 psi. Drill 6-3/4" Production section F/ 5722' MD T/ 5950' MD. Added .5% by volume on NXS lube to active system.
P/U-85K S/O-55K ROT-65K GPM-180 SPP-1280 psi TQ-8.4K RPM-60 Flow-14% ROP-50 WOB-2/6.5K Diff-116 psi MW-9.1 ppg ECD-10.2 ppg Max gas -132
units. Crew change, held PTSM. Cont. drilling 6.75" production hole F/5950' to current depth of 6171'. Brought lube percent to 1% by volume to help reduce TQ.
P/U-88K S/O-56K ROT-68K GPM-180 SPP-1370 psi TQ-9.2K RPM-60 Flow-16% ROP-50 WOB-6/7K. Diff-205 psi MW-9.4 ppg ECD-10.46 ppg Max gas -1000
units. Distance to well plan: 6.11' 5.17' High 3.26' Left.
7/12/2023 Drill 6-3/4" Production section F/ 6171' T/ 6330' GPM 180 SPP 1400 RPM 60 WOB 6K On Bottom TQ 9K PUW 92K SOW 56K ROT 71K Max Gas 671 units.
M/W in 9.4ppg M/W out 9.4ppg ECD 10.64ppg. SPRs @ 6239' MD 5992' TVD MP#1 15 SPM 284 psi 25 SPM 399 psi MP#2 15 SPM 276 psi 25 SPM 389 psi,
72 Hour Notification to test BOPE sent to BLM @ 06:04. Drill 6-3/4" Production section F/ 6330' T/ 6525' GPM 180 SPP 1500 RPM 60 WOB 6K On Bottom TQ
9.8K PUW 96K SOW 56K ROT 71K Max Gas 658 units. M/W in 9.4+ppg M/W out 9.4+ppg ECD 10.80ppg. Pumped 20 BBL Hi-Vis Con Det/ Nut Plug sweep.
Drill 6-3/4" Production section F/6525'-T/6700'. Sweep came back 12.5 bbls early w/ a 30% increase in cuttings. P/U-96K S/O-57K ROT-70K GPM-180 SPP-
1515 psi TQ-10K RPM-60 Flow-15% ROP-50 WOB-5K Diff-240 psi MW-9.45 ppg ECD-10.75 ppg Max gas -1014 units. Crew change, held PTSM. Cont. drilling
6-3/4" Production section F/6700' to current depth of 6833'. P/U-98K S/O-58K ROT-71K GPM-180 SPP-1530 psi TQ-10K RPM-60 Flow-15% ROP-50 WOB-6K
Diff-300 psi MW-9.4 ppg ECD-10.8 ppg Max gas -241 units. Distance to well plan: 9.26' 7.68' High 5.16' Left.
7/13/2023 Drill 6-3/4" Production section F/ 6833' T/ 7048' GPM 180 SPP 1565 RPM 60 WOB 6K On Bottom TQ 10.8K ft/ lbs. PUW 95K SOW 57K ROT 69K Max Gas 819
units. M/W in 9.4ppg M/W out 9.45ppg ECD 10.81ppg. Drill 6-3/4" Production section F/ 7048' T/ 7199' MD 6944' TVD GPM 180 SPP 1581 RPM 60 WOB 6K
On Bottom TQ 11K ft/ lbs. PUW 96K SOW 57K ROT 70K Max Gas 322 units. M/W in 9.4ppg M/W out 9.45ppg ECD 10.9 ppg. Obtain on bottom survey. Pump
20 BBL Hi-Vis Con Det/ Nut Plug sweep while reciprocating and rotating. GPM 180 SPP 1350psi RPM 45 Off Bottom TQ 9.5K ft/ lbs. Sweep came back 6-1/2
BBLs early with 50% increase in cuttings. Circulate until shakers clean. Obtained new SPR's. Flow checked well (static). POOH on elevators F/7199'-T/5926' w/
5-10K drag during trip. Hole started swabbing. M/U TD, broke circ. observed packing off, staged up MP, kicked in rotary, worked std. and CBU. P/U-64K S/O-
58K ROT-60K. M/U TD, broke circ. observed packing off, staged up MP, kicked in rotary, worked std. and CBU. P/U-64K S/O-58K ROT-60K GPM-170 SPP-967
psi RPM-60 TQ-8.8K Flow-15% MW-9.45 ppg ECD-10.47 ppg Max gas- 449 units. Pumped OOH F/5926'-T/5799'. P/U-80K S/O-46K GPM-160 SPP-904 psi
MW-9.45 ppg ECD-9.95 ppg Max gas- 294 units. BROOH F/5799'-T/5673' due to over pulling and pressuring up and packing off while pumping OOH. P/U-78K
S/O-62K ROT-70K GPM-160 SPP-. 956 psi RPM-30. Cont. pumping OOH F/5673'-T/3950'. P/U-76K S/O-44K GPM-160 SPP-798 psi. Calculated hole fill - 21.31
bbls Act- 27.7 bbls Diff- 6.39 bbls over. Pumped 20 bbl Low-Vis sweep w/ walnut & condet, sweep came back on time w/ a 20% increase in cuttings. Flow
checked well (static). POOH on elevators F/3950'-T/2779' w/ no issues. P/U-62K S/O-41K. Rig service - Greased & inspected crown, blocks, TD, DWKS, IR,
wash pipe, brake linkage, and drive shaft. Currently changing out saver sub on TD. Distance to well plan: 19.28' 13.39' High 13.87' Left.
7/14/2023 POOH on elevators F/ 2779' T/ 740' @ 30 FPM w/ no issues. P/U 45K S/O 33K. Calculated Hole Fill 50.8 BBLs Actual Hole Fill 59.95 BBLs. Stand back 5
stands of HWDP, Jar stand, 3 stands HWDP & Flex Collars. PJSM & remove sources. Download MWD Data. L/D TM, PWD, CTN, ADR, PCG & DM collars.
Break bit F/ motor and L/D motor. Bit graded a 1-1. Clean & clear rig floor, Pull wear ring, Function & flush BOPE stack. Grease all components for upcoming
BOPE Test. C/O Actuator assembly for Top Drive IBOP. R/U Test assemblies for testing w/ 3-1/2" & 4-1/2" test joints. Install Test Plug w/ 3-1/2" Test Joint.
Purge all lines & equipment. Perform shell test. Quadco rep test all gas alarms with visual and audible witnessed by AOGCC. Perform Bi-Weekly BOPE Test
250 low for 5 min each & 3500 high test for 10 min each with 3-1/2" & 4-1/2" Test joints. Had 1 FP on test #6. Choke HCR, functioned choke HCR, and retested -
Pass. 5.5 hr. test time. R/D testing equip. Pulled test plug. Noticed gas breaking out in well bore. installed 9" wear ring. Filled stack w/ mud. Monitored well on
TT. P/U & M/U 6.75" cleanout assy.- BHA #7. RR 6.75" PDC bit, bit sub w/ float, stab, and flex collars. Crew change, held PTSM. RIH F/surface-T/682'. Max gas
571 units. CBU X3. staging up MP. GPM-60-104 SPP-0 F/ow-10-15% MW-9.4 ppg Max gas -1504 units. Cont. RIH F/682'-T/1308'. P/U-20K S/O-20K Flow-9%
Max gas 739 units. CBU staging up MP. GPM-80-180 SPP-170 psi Flow-9-18% MW-9.45 ppg Max gas -4614 units. Cont. circulating out gas while weighting up
mud system to 9.55 ppg. Gas decreased to 462 units. Shut down MP. Flow checked well - Initial = 3.5 bph, increased to 4 bph in 5 min. Resumed circ. while
waiting up mud system to 9.6 ppg. GPM-180 SPP-211 psi Flow-17% Max gas - 4457 units. Resumed RIH w/ BHA #7 F/1308' to current depth of 1990'.
gj
Quadco rep test all gas alarms with visual and audible witnessed by AOGCC
Drill 6-3/4" Production section F/ 7048' T/ 7199' MD
7/15/2023 Cont. RIH with 6-3/4" cleanout BHA #7 F/ 1990' T/ 2760' with no issues. P/U 43K S/O 35K. Circulate two bottoms up to remove gas from wellbore & assure MW
is 9.6+ throughout. GPM 160 SPP 240-270psi. Max Gas 4846 units. RIH F/ 2760' T/ 4336' with no issues P/U 63K S/O 43K. Circulate two bottoms up to remove
gas from wellbore & assure MW is 9.6+ throughout. GPM 160 SPP 350-360psi. Max Gas 4883 units. RIH F/ 4336' T/ 5880' with no issues P/U 80K S/O 46K.
Circulate two bottoms up to remove gas from wellbore & assure MW is 9.6+ throughout. GPM 160 SPP 470psi. Max Gas 4636 units. RIH F/ 5880' T/ 7000' with
no issues P/U 88K S/O 44K. Fill pipe & wash down & locate fill at 7051'. Wash & ream F/ 7051 T/ 7189' GPM 180 SPP 815psi RPM 30. Lost all returns at 7189'.
POOH F/ 7189' T/ 7085' to build LCM pill & keep hole full with trip tank. P/U 140K S/O 75K ROT 110K RPM 45 Max Gas 3200 units. Build 30 BBLs of 40 PPB
LCM pill. RIH and clean out to 7199' & lay in 25 BBLs 40 PPB LCM Pill. POOH F/ 7185' T/ 6585' & attempt to circulate at 1-1/2 BPM with no success. Decision
made to wait until 18:00 hours & work pipe occasionally along with keeping well full with hole fill pump on trip tank. Allow LCM Pill to soak. Monitor Well on trip
tank with a static loss rate of 1.5 BPH loss. Broke circ. w/ MP at idle - GPM-56 SPP-231 psi Flow-2%. Staged up pump - GPM-93 SPP-312 psi Flow-0%. lost
returns. P/U-118K S/O-76K Started mixing 80 ppb LCM pill. TIH F/6587', tagged up at 7194'. Washed to bottom- GPM-56 SPP-311 psi P/U-128K S/O-78K
Dynamic loss rate = 73 bph. Lined up hole on TT, monitored hole and worked pipe every 5-10 mins while finishing mixing LCM pill. Static loss rate = 6.24 bph.
Pumped and spotted 80 ppb LCM on bottom - GPM-93 SPP-416 psi Flow-0%. Dynamic loss rate = 26.8 bph. Regained flow while spotting LCM pill- Flow
climbed to 8%. Max gas 3702 units. Shut down MP, flow check (slight seepage). POOH on elevators F/7199'-T/6577' at 15-20 fpm. Had calculated hole fill
during trip. P/U-131K S/O-79K. Lined up hole on TT, monitored hole, worked pipe every 5-10 mins while letting LCM pill soak. Initial static loss rate = 1.26 bph.
Final static loss rate = .66 bph. Crew change, held PTSM. Broke circ. w/ MP at idle- GPM-69 SPP-358 psi Flow-7% Max gas- 3045 units P/U-110K S/O-76K.
Pumped STS to even out MW w/ centrifuge to 9.6 ppg. Initial dynamic loss rate = 1.26 bph. Final dynamic loss rate = .66 bph. Staged up MP after getting in/out
MW down to 9.6 ppg. GPM-145 SPP-550 psi Flow- 13% Gas - 35 units. Dynamic loss rate- 15 bph. Static loss rate - 0 bph. RIH on elevators F/6553' at 15-20
fpm w/ no issues. Tagged bottom at 7199' w/ no fill. Flow check rate - .6bph. L/D E-Kelley in string. P/U-119K S/O-76K. Attempted to POOH on elevators w/ no
luck (swabbing). Pumped OOH F/7130' to current depth of 6621'. Lost 428 bbls to the well over last 24 hrs.
7/16/2023 Pumped OOH F/ 6621' T/ 6619' SPM 56 SPP 250-350psi. P/U 122K S/O 77K. POOH on elevators F/ 6619' T/ 2723' P/U 112K S/O 68K. Service & Inspect
Crown, Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor Motor, Draworks, Crown-O-Matic, Gear Box, Drive Line & Brake Linkage. Static Loss Rate @ 1.74
BBLs per hour. POOH on elevators F/ 2723' T/ 1200' P/U 57K S/O 42K. Calculated Fill 36.1 BBLs Actual Fill 44.9 BBLs. POOH F/ 1200' T/ Surface laying down
6-3/4" Cleanout BHA # 7. Calculated Fill 13.41 BBLs Actual Fill 17.63 BBLs. Cleared and Cleaned Rig Floor, R/U Parker Tubular Running Services and M/U
Floor valve with proper crossovers for Liner. Monitor well on trip tank w/ static loss rate of 2 BPH. PJSM, Baker-Lok shoe track and confirm floats working
properly. RIH with 3-1/2" 9.2# L-80 THS Wedge 563 Range II Liner as per approved tally F/67'-T/3838'. Calculated Disp.-13.04 bbls Act - 10.86 bbls Diff- 2.18
bbl loss to hole. P/U-38K S/O-32K. Submitted 48 hour notice to AOGCC for MIT test @ 18:55 on AOGCC web site. Crew change, held PTSM and weekly safety
meeting w/ rig crew. Cont. RIH with 3-1/2" 9.2# L-80 THS Wedge 563 Range II Liner as per approved tally F/3838'-T/4643'. Calculated Disp.-16.22 bbls Act -
15.85 bbls Diff- .37 bbl loss to hole. P/U & M/U ZXP hanger/packer as per Baker rep to 3.5" liner. Mixed up and poured into top of hanger Zan-plex. M/U XO to
liner hanger running tool, RIH w/ hanger/packer on 1 std of 4.5" DP. Circulated string volume to break gel strengths and displace liner string of fresh mud. P/U-
48K S/O-38K GPM-88 SPP-208 psi Flow-10% MW-9.6 ppg Max gas -1384 units. Cont. RIH with 3-1/2" 9.2# L-80 THS Wedge 563 Range II Liner F/4695'-
T/5735' at 15 fpm. M/U TD, broke circ. Staging up MP. Circulating BU at time of report. GPM-94 SPP-233 psi Flow-10% MW-9.6 ppg Max gas -2766 units.
7/17/2023 Complete Circulating BU. GPM-94 SPP-233 psi Flow-10% MW-9.6 ppg Max gas -4507 units. Continue RIH with 3-1/2" Liner with DP from Derrick F/ 5735' T/
7106' @ 15 FPM P/U 62K S/O 49K Calculated displacement 67.46 BBLs Actual displacement 62.61 BBLs. Fill Pipe P/U and M/U 15' Pup and RIH with stand #
41 & M/U Baker Cement head with 10' pup on bottom T/ 7189'. CBU @ 3 BPM SPP 385psi. Flow 11%. PJSM with all personnel for cement job, Pump 5 BBLs
water to flush line from cementers. PT Lines against Lower TIW on Cement head with manual and hydraulic Top Drive IBOP valves shut. 400psi low & 5000psi
High. Good Test. Open Lower TIW on. Cement head and pump 30 BBLs 10.5ppg Tuned Spacer at 3 BPM at 527psi. Pump 451 SKS Lead Cement at
12.00LB/GL 2.39FT/SK 14.07GL/SK Pumped a total of 192BBLS of Cement at 3BPM 101PSI. Pump 118 SKS of Tail Cement at 15.30LB/GL. 1.24FT/SK
5.58GL/SK Pump a total of 25.9BBLS of Cement at 3BPM 93PSI. Shut lower TIW on Baker Cement Head and open quarter turn valve to cuttings box and wash
pumps and lines with water to cuttings box. Shut quarter turn valve to cuttings tank. Open lower TIW on Baker Head. Launch Drill Pipe Wiper Dart witnessed by
DSM. At 33.5 BBLs into displacement pump kicked out at 1400psi. (Calculated Displacement 75 BBLs) Bleed off and try again with no movement 6 times.
Discuss results with Drilling. Engineer and Town Team. Attempt to set liner with no results. Decision made to pull Liner assembly. Bleed off all pressure & break
off hoses & tees from cement head. Install 1502 caps. POOH F/ 7197' T/ 4589. L/D cement head and 10' Pup Jt. & L/D ZXPN Flex Lock V-DG assembly. Dump
retarder down Liner string & Pump 40 BBLs citric water followed by 40 BBLs of 9.6ppg mud. Inspect Liner Hanger & Locate DP Wiper Dart in Pusher Tool below
the 3-1/2" Baker drill pipe sub. 800 bbls into displacing water out of 3.5" liner lost returns. Shut down. pump. Lined TT up on the hole, filled backside, got well
stood up. Monitored well on TT. Initial loss rate -19.4 bph. R/U TRS casing equip. POOH L/D 3.5" liner F/4589'-T/1124', running water through each jt. to flush
tubulars, vacuuming out the water and re-doping threads on the catwalk racks. Crew change, held PTSM. Cont. L/D 3.5" liner F/1124'-T/shoe track. M/U XO to
shoe track. Pumped water to flush and cleanout shoe track. GPM-127 SPP-0. Heated and B/O Baker-Lok joints, L/D shoe track. Calculated hole fill - 15.9 bbls
Act- 18.06 bbls Diff- 2.16 bbls. Monitored well on TT. R/D TRS casing equip. Cleaned & cleared rig floor. P/U and B/O XO's on Baker hanger and cmt head.
Johnny Whacked stack. Currently servicing rig.
7/18/2023 Service and Inspect Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor Motor (Change Filters), Draworks, Crown-O-Matic, Gear Box, Drive Line and Brake
Linkage. R/U Parker casing equipment and remove float equipment from joints of liner & crossovers for Landing Collar. New Float equipment ordered for next
liner run. R/D Parker casing equipment. P/U & M/U 6-3/4" Cleanout BHA #8. Tri-Cone Bit, Bit Sub, 6.625" Stabilizer, 2 4-3/4" Non Mag Flex Collars, 6" Stabilizer,
6 Jts. 4-1/2" HWDP, 4-3/4" Jar and 11 Jts. 4-1/2" HWDP T/ 630'. RIH with 6-3/4" Cleanout BHA #8 with 4-1/2" 16.60# S-135 Range II CDS40 Drill Pipe F/ 630' T/
4604' set down on cement stringer 10k three times, kelly up and wash and ream through hard cement t/ 4608' continue taking weight and seeing stringers wash
and ream in the hole t/ 6917' 125 gpm 55 rpm. 99% cement cuttings returns 1% formation, unable to RIH on elevators taking weight and sticky on the P/U, Max
Gas observed 5000+ units @ 5032' CBU gas dropped off on bottoms up.
7/19/2023 Continue washing and reaming in the hole F/ 6917' T/ 7150' (PBTD) 6895' TVD GPM 126 SPP 400-500psi RPM 50 Max Gas 3215 units. MW in 9.7ppg MW out
9.7+ppg. Condition mud and circulate 2 sweeps to remove cement from well. Sweep #1 20 BBL Hi-Vis Con Det/ Nut Plug GPM 126 SPP 300-400psi. RPM 50
Returned on time W/ 10% Increase Sweep #2 20 BBL Hi-Vis Con Det/ Nut Plug GPM 126 SPP 300-400psi. RPM 50 Returned on time W/ No increase in
cuttings. SPRs @ 6895' TVD 9.5+ppg MP #! SPM 21 SPP 151psi MP #2 SPM 21 SPP 148psi. Flow Check well: Static. POOH with 6-3/4" Cleanout assembly on
elevators F/ 7150' T/ 2735'. P/U 52K S/O 42K. Calculated Hole Fill 28 BBLs Actual Hole Fill 30.9 BBLs. Monitor well on trip tank while waiting on Liner
equipment. Change out Teflons on Top Drive Torque Bushing, work on housekeeping and general maintenance, TMC working on Lewis river pad pre rig.
Continue working on general maintenance and housekeeping, organize c cans and rig, monitor well on trip tank, straighten torque tube, Work on trip tank pump.
7/20/2023 Continue Waiting on Liner Hanger & Float Equipment. Line well up on Pit #6 & replace Trip Tank pump. Swap well back T/ Trip Tank & continue monitoring well
on trip tank. Relocate switch on Drillers Console. Change Grabber Box Dies. Torque Iron Roughneck Bolts. Continue organizing & housekeeping around rig &
location. Continue Waiting on Liner Hanger & Float Equipment. Monitoring Well on Trip Tank. Diagnose & repair water tank pump for LRU D Pad well.
Disassemble Fluid ends on MP#1 & MP#2, Inspect & re-assemble. Disassemble hoppers, Inspect & re-assemble. Continue waiting on hanger and float
equipment, continue monitoring well on trip tank, continue general maintenance and housekeeping, offload 379 barge of miscellaneous equipment,. Continue
monitoring trip tank, perform general maintenance and housekeeping, back ground gas increasing. CBU Max gas 5000+ unit not falling off after bottoms up,
decided to RIH to bottom and circulate mud around. RIH f/ 2735' t/ 4711' CBU@ 3963' Max gas seen 5000+ units not falling off again, no increase in gain loss of
flow, no hole issues.
Lost all returns at 7189'.
POOH F/ 7189' T/ 7085' to build LCM pill & keep hole full with trip tank. P/U 140K S/O 75K ROT 110K RPM 45 Max Gas 3200 units.Build 30 BBLs of 40 PPB
LCM pill.
qp j g qp
P/U & M/U 6-3/4" Cleanout BHA #8. Tri-Cone Bit, Bit Sub, 6.625" Stabilizer, 2 4-3/4" Non Mag Flex Collars, 6" Stabilizer,g g
6 Jts. 4-1/2" HWDP, 4-3/4" Jar and 11 Jts. 4-1/2" HWDP T/ 630'. RIH with 6-3/4" Cleanout BHA #8 with 4-1/2" 16.60# S-135 Range II CDS40 Drill Pipe F/ 630' T/g p
4604' set down on cement stringer 10k three times, kelly up and wash and ream through hard cement t/ 4608' continue taking weight and seeing stringers washgy g
and ream in the hole t/ 6917' 125 gpm 55 rpm. 99% cement cuttings returns 1% formation
gg pppy
Submitted 48 hour notice to AOGCC for MIT test @ 18:55 on AOGCC web site
Continue RIH with 3-1/2" Liner with DP from Derrick F/ 5735' T/
7106'
Cont. RIH with 6-3/4" cleanout BHA #7 F/ 1990' T/ 2760' with no issues. P/U 43K S/O 35K. Circulate two bottoms up to remove gas from wellbore & assure MW
is 9.6+ throughout
Continue washing and reaming in the hole F/ 6917' T/ 7150' (PBTD
g
Monitored well on TT. Initial loss rate -19.4 bph.
Started mixing 80 ppb LCM pill
()yg
Attempt to set liner with no results. Decision made to pull Liner assembly.
7/21/2023 RIH F/ 3963' T/ 4890' @ 50 FPM with no hole issues. P/U 72K S/O 55K. Circulate and Condition to remove gas from wellbore. GPM 125 SPP 225psi Max Gas
5000 units with no gains or losses T/ PVT. MW in 9.5+ MW out 9.5+. RIH F/ 4890' T/ 6130' @ 50 FPM with no hole issues. P/U 118K S/O 68K. Calculated
Displacement 67.1 BBLs Actual Displacement 68.36 BBLs. Circulate and Condition to remove gas from wellbore. GPM 125 SPP 250psi Max Gas 5000 units
with no gains or losses T/ PVT. MW in 9.5 MW out 9.5+. RIH F/ 6130' T/ 7150' @ 50 FPM, Washing & Reaming through 7058' & 7123'. P/U 125K S/O 70K.
Calculated Displacement 18.3 BBLs Actual Displacement 16.17 BBLs. Pump Hi-Vis sweep and continue Circulating T/ clean up well and remove any gas. GPM
126 SPP 448 RPM 32 TQ 9.9K Max Gas 4480 units with no gains or losses. Sweep back on time with no increase in cuttings. Max Gas 4480 units. POOH F/
7150' T/ 6484' P/U 138K S/O 76K Calculated Hole Fill 4.1 BBLs Actual Hole Fill 3.4 BBLs. Monitor well on Trip Tank. POOH on elevators f/ 6484' t/ 2725' no
hole issues. Service rig, grease blocks and crown, inspect draw works. monitor well on trip tank well static, work on EAM's and general housekeeping. RIH f/
2725' t/ 5756' No hole issues filled pipe @ 4279'.
7/22/2023 RIH W/ 6-3/4" Cleanout BHA #7 F/ 5756' T/ 7150' filling pipe every 1500' with no issues. P/U 132K S/O 78K Calculated Displacement 85.4 BBLs Actual
Displacement 85.17 BBLs (Displacement: entire trip F/ 2725' T/ 7150'). Circulate to remove gas from wellbore GPM 127 SPP 275psi. Flow 14%. Max Gas 5000
units. Flow Check: Slight Seepage. POOH F/ 7150' T/ 2600'' P/U 50K S/O 30K Calculated Hole Fill 30.15 BBLs Actual Hole Fill 31.04 BBLs (2.39" drift was
dropped at 6484' E-Kelly joint was drifted before dropping down string). Liner equipment arrived on location & verified correct. Drift Crossover Joint with 2.867"
Drift. Drifted running tool on Liner Hanger with 1.92" drift. Good. Cleaned connections to be Baker-Lok & Thread Protectors. Drifted XO and 5' pup installed on
bottom of cement head with 2.39" Drift. Flow Check, Slight Seepage POOH F/ 2600' T/ 630' P/U 50K S/O 30K Calculated Hole Fill 10.05 BBLs Actual Hole Fill
10.66 BBLs. Stand Back HWDP, L/D Jars & 1 Jt. HWDP, Stabilizer, Flex Collars, Stabilizer, Bit Sub & Bit. Bit Graded 1-1. Calculated Hole Fill 7.5 BBLs Actual
Hole Fill 8.4 BBLs. Clean & Clear Rig Floor. Remove subs not needed. Bring up centralizers, M/U Floor Valve with proper crossovers, R/U Parker TRS Tongs &
Fill up hose. PJSM with all parties involved with picking up & running 3-1/2" 9.2# L-80 RangeII THS Wedge 563 Liner. Baker-Lok Shoe Track & confirm that
floats are working as designed. RIH with 3-1/2" Liner as per tally details F/ 100' T/ 4525' Make up Hanger and running tool, Mix pal mix, R/D TRS, P/U 1 stand of
DP. Pump liner volume 121 gpm 174 psi. Continue RIH w/ 3.5'' Liner on 4.5'' DP f/ 4525' t/ 7111' Wash last stand to bottom 7150' no fill. Circulate and condition
mud f/ cement job, spot in cementers and R/U, Change out pups on cement head. Stand back stand, P/U single and cement head, R/U circulating equipment
and stae pumps t/ 4 bpm 392 psi. PJSM, Pump 5 bbls of water ahead shut down and PT lines, 400/4700 psi, Pump 30 bbls 10.5 ppg spacer at 4 bpm pump 188
bbls of 12 ppg lead cement at 4 bpm, 23 bbls 15.3 ppg Tail at 4 bpm, wash up over the top of the cement head, Drop top plug and kick out with 10 bbls of water.
7/23/2023 Drop drill pipe wiper dart (DSM witnessed tattle tale function) and kick out with 10 bbls of water followed by 9.6ppg mud. Displaced 34 BBLs total when Cement
Kick-Outs tripped W/ 1570psi. Reset Kick-Outs T/ 3000psi and moved dart & landed dart at. Landing collar with 74.5 BBLs displaced. Pressure up T/ 2338psi &
set hanger, Pressure up T/ 2550psi & set Packer. Pressure up T/ 3815psi & release running tool. Bleed back 1 BBL & float checks are good. L/D Cement head
& M/U Top Drive T/ string &. pressure up and pull slick stick. Pump @ GPM 210 SPP 126-317psi & CBUx2. Returned 30 BBLs Spacer & 65 BBLs of Lead
cement to pits. Total losses during entire job was 15 BBLs. CIP @ 06:46. L/D 15' pup jt & E-Kelly jt. POOH F/ 2547' T/ Running tool. Break running tool in half &
L/D. Calculated Fill 14.07 BBLs. Actual Fill 14.29 BBLs. P/U Stack washer & wash BOPE stack with black water and surface lines. P/U & B/D cement head. P/U
& M/U TBR Polish Mill assembly. RIH F/ Surface T/ Locate liner top at 2597'. Polish TBR as per Baker representative. P/U 38K S/O 32K. Swap well over T/
8.4ppg CI water while washing out both mud pumps. GPM 197 SPP 221psi. Flow Check well for 30 minutes & confirm Good No Flow Test. POOH L/D Drill Pipe
F/ 2585' T/ Surface L/D polish mill, RIH w/ remaining DP f/ derrick and POOH L/D same, Lay felt liner and Mats on Lewis River Pad. Clear floor, Pull wear ring
and RIH w/ Brush and flush hanger pocket. R/U and test casing liner top t/ 3500 psi f/ 30 min on chart, good test, R/D test equipment. R/U Parker Casing, PJSM,
P/U seal assembly and torque SSSV.
7/24/2023 RIH W/ 5-3/4" Bullet Tie-Back Seal assembly F/ 15' T/ 1073' with correct displacement. Service & Inspect Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor
Motor, Draworks, Crown-O-Matic, Gear Box, Drive Line & Brake Linkage. Pollard is flying over this morning on Alaska West since the Otter could not
accommodate us. We are currently ready T/ P/U Chemical Injection Mandrel. R/U Pollard & Cont. RIH with 3-1/2" 9.2# L-80 Range II TSH Wedge 563 Tie-Back
assembly F/ 1073' T/ ' Locate Liner Top and tag No-Go with seal assembly @ 2607' Bullet Seal Assembly Depth. Lay down 2 jts. & M/U 2 Pups & Hanger. Route
both control lines through. Hanger and secure. Land Hanger with 22K down. Test seals from in between T/ 5000psi. Engage and confirm Lockring engaged with
40K Pull on elevators. Back out landing jt and L/D, R/U and test tubing to 3500 psi f/ 30 min on chart pumped 35 gal bled back 35 gal, test IA to 2500 psi f/ 30
min on chart pump 47.5 gal bled back 42.5 gal R/D test equipment. Install TWC, Flush lines, choke manifold and gas buster with baraclean pill, blow all lines
down. Open ram doors and inspect and clean cavities, close and retorque ram doors. N/D choke and kill lines, N/D flow riser and flow line, Pull flow box, N/D
BOP Stack, R/D pits and pump modules, Move all third party equipment away from rig. N/U dry hole tree and test as per wellhead rep. Change AFE to LRU C-02
@ 0600hrs.
7/30/2023
Make up Hanger and running tool, Mix pal mix, R/D TRS, P/U 1 stand ofgg
DP. Pump liner volume 121 gpm 174 psi. Continue RIH w/ 3.5'' Liner on 4.5'' DP f/ 4525' t/ 7111' Wash last stand to bottom 7150' no fill. Circulate and conditionpgpp
mud f/ cement job, spot in cementers and R/U, Change out pups on cement head. Stand back stand, P/U single and cement head, R/U circulating equipmentjg gg
and stae pumps t/ 4 bpm 392 psi. PJSM, Pump 5 bbls of water ahead shut down and PT lines, 400/4700 psi, Pump 30 bbls 10.5 ppg spacer at 4 bpm pump 188p p p p p p p ppg pppp
bbls of 12 ppg lead cement at 4 bpm, 23 bbls 15.3 ppg Tail at 4 bpm, wash up over the top of the cement head, Drop top plug and kick out with 10 bbls of water.
gg g
PJSM with all parties involved with picking up & running 3-1/2" 9.2# L-80 RangeII THS Wedge 563 Liner. Baker-Lok Shoe Track & confirm thatggpppgpg
floats are working as designed. RIH with 3-1/2" Liner as per tally detaigg y
g
Returned 30 BBLs Spacer & 65 BBLs of Leadpgppp p@
cement to pits. Total losses during entire job was 15 BBLs. CIP @ 06:46.
g
Cont. RIH with 3-1/2" 9.2# L-80 Range II TSH Wedge 563 Tie-Backyy j g g
assembly F/ 1073' T/ ' Locate Liner Top and tag No-Go with seal assembly @ 2607' Bullet Seal Assembly Depth. Lay down 2 jts. &M/U 2 Pups & Hanger. Routeygy@yyjg
both control lines through. Hanger and secure. Land Hanger with 22K down. Test seals from in between T/ 5000psi. Engage and confirm Lockring engaged withgg g pgg ggg
40K Pull on elevators. Back out landing jt and L/D, R/U and test tubing to 3500 psi f/ 30 min on chart pumped 35 gal bled back 35 gal, test IA to 2500 psi f/ 30gj
min on chart pump 47.5 gal bled back 42.5 gal R/D test equipment
Activity Date Ops Summary
6/12/2023
7/29/2023 Fly to Beluga. PJSM and PTW, SIMOPS meeting with production and construction. Mobe equipment from C pad to E pad. MIRU Fox coil tubing, Rain for Rent
tanks, and Cruz crane. N/U BOPES, run choke, and kill lines. Fluid pack BOPEs. BOPE test per Hilcorp and AOGCC regulations. Test to 250psi/2500psi - TEST
GOOD. Witness waived by AOGCC, Jim Regg via email on 7/28/23 @ 0925hrs. Fill rain for rent tank supply tank with fresh water. M/U YJ coil tubing connector
and pull test to 20k. Secure equipment and SDFN.
7/30/2023 PJSM and PTW. SIMOPS meeting with production and construction. SITP 0psi,P/U injector, M/U lubricator. M/U BHA CTC, DFCV, Disconnect, stinger, 2.80"
OD down jet nozzle. Fill reel, pressure test connector to 3,500psi. Stab on well and Pressure test stripper, lubricator and pump iron to 250psi/2,500psi - TEST
GOOD,Open well and RIH, had to pump to get into the liner top at 2,635'. Dry tag at 7,093', bring on pump at 1.75BPM and wash to 7,097'. Circulate 2x bottoms
up (105bbls) displacing drilling mud to fresh water. Returns clean POOH, rolling pumps to keep the well full. Secure well. Breakdown BHA,Wait on otter
mechanical for E-Line crew. Dispose of drilling mud. Fill N2 pump,PJSM and PTW for E-line. Spot E-line equipment, M/U Lubricator, R/U 1-11/16" CBL tools.
Stab E-line adapters on coil BOPEs. Lay down lubricator. SDFN.
7/31/2023 PJSM and PTW, SIMOPS with production and construction. SITP 0psi,M/U 1-11/16" CBL tools. P/U lubricator and stab on top of the coil BOPEs. Pressure test
lubricator 250psi/2500psi - Test Good,RIH tag PBTD at 7,074'. Pull CBL log and send to town. Log approved by town. RDMO AK E-line. PJSM and PTW with
Fox Coil. R/U N2 pump, M/U lubricator and BHA. CTC, Stinger, 2.125" Nozzle. Stab on well and PT pump and lubricator to 250/2500 psi. RIH to 5,550ft. PT N2
lines to 3,500 psi. Come online with N2 at 1,500 SCFM. RIH and tag PBTD at 7,097', continue pumping N2 reversing out wellbore fluid. POOH. All wellbore fluid
recovered 94BBL total (64BBL Well volume + 30BBL Coil volume). Trap 1750psi of N2 on the well,Secure well. Lay down the lubricator, place the injector in the
rack. R/D iron and BOPE. SDFN.
8/2/2023 PJSM and PTW, SIMOPS with production and construction. SITP 1800psi of N2,Spot equipment, transfer E-line grease from drums to crane truck. R/U AK E-
line. Wait on guns. Receive a sling load of guns from the helicopter. M/U weight bars, gun gamma, and 10ft 2-3/8"OD Geodynamics 6SPF, 11gm gun (CCL to
top shot 13.2'). Stab on well and pressure test lubricator. Wireline valves leaking, swap out wireline valves for back-up set. Pressure test lubricator to
250psi/2500psi - Test good,RIH and tag PBTD at 7,079'. Pull correlation log and send to town. Shift -5ft (uphole). Pull on depth and perforate the Beluga J4
sands from 6,911-6,921'. POOH. Bull plug damp with a little fine Beluga sand in it. No pressure change observed. SITP steady at 1841psi,M/U weight bars, gun
gamma, and 13ft 2-3/8"OD Geodynamics 6SPF, 11gm gun (CCL to top shot 14.3'). Pull correlation log. Pull on depth and perforate the Beluga J1 sands from
6,635-6,648'. POOH. Bull plug damp with a little fine Beluga sand in it. SITP. 0min - 1841psi. 15min - 1874psi,M/U weight bars, gun gamma, and 14ft 2-3/8"OD
Geodynamics 6SPF, 11gm gun (CCL to top shot 13.2'). Pull correlation log. Pull on depth and perforate the Beluga I7 sands from 6,318-6,6,332'. POOH. Bull
plug damp with a little fine Beluga sand in it. SITP. 0min - 1924psi. 15min - 1949psi,Secure well, lay down lubricator. SDFN.
8/5/2023 Mobe E-line crew & tools to Beluga, PTW, PJSM,Spot Eq. at wellsite,,R/U, W/GPT tool string. Mobe Test pump skid, stab lubricator, P/T 250/3500, good,RIH
finding fluid level @4929', cont. RIH t/~7020' , WHP 2134psi. Log accross perfs while flowing well & bleeding to 0 psi, finding temp change at lowest perfs only,
& fluid level @2450',Cont. POOH, secure well & l/d e-line tools. SDFN.
8/6/2023 PTSM, Simops, PTW,Warm Eq. check pressures, wellhead 1655psi, IA-0, Start pumping n2, ~1900 started having issues with discharge line icing,,Troubleshoot
& let lines warm, adjust cooling line, fire up & start building pressure good,Continue pumping operations, wellhead pressure hit 2270 psi then started leveling off
and dropping, over next hour t/ 2220~ psi,,R/U e-line w/GPT tool string, PT lub, 3500 good, RIH finding fluid @ 4410',Continue pumping N2 to push fluid below
goal of 6300' Pressure started climbing t/ 2320 fluid level @ 4430',Continue pumping n2 monitoring pressure & fluid level, pressure increased t/2772psi, fluid
4596', when n2 pump broke down, ( appears to be cold end of pump),Take one more fluid level on way out of hole @ 4612', pressure had dropped to 2739psi.
R/D pump & POOH w/ e-line, secure well. L/d lubricator, discuss options for replacement pump. R/D e-line. ( sending crews in until replacement pump & more
N2 arrives in Beluga.).
8/10/2023 Fox N2 crew travel to Beluga River. PJSM & permit. Fire up equipment. PT surface equipment 500 / 3500 PSI. Good. Began pumping N2 down well. 15:20 Start
PSI at 2300,1000 scf away at 800 scf rate. End PSI 3200, 17,749 scfs away at 300 scf rate. Tank volume start 49". Tank volume end 40". Total gallons used
340. SCF's used 31,717. SCF pumped 17,749. Pump off line. SDFN. Plan forward: Monitor pressure overnight for bleed down.
8/11/2023 Fox N2 PJSM and permit. Travel to location. Fire up N2 equipment. Start pumping N2. Start PSI 2790 at slow steady 300 scf per minute rate. End PSI 3100. AK
E-Line on weather hold at airport. Weather cleared. Crew traveled to Beluga. Checked in. PJSM and permit. Mobe equipment to location. Change out panel in
order to run switch guns. Rig up AK E-Line. Attempt to PT surface equipment. Held low at 250 but small leak on BOP at 2870 PSI N2. Lay down 3" BOP. Pick up
4" BOP & stab back on. PT 250 / 2870 PSI. Test good. RIH w/ GPT. Found FL at 6370' after adjusting scale. Max depth ran was 6460'. POOH logging to 5260'.
Continue OOH. Sent log to town. Adjusted down 3'. OOH. Lay down GPT. Make up 3-1/2" CIBP. RIH w/ 3-1/2" (2.75") CIBP to be set at 6268', CCL to top of plug
= 12.4' / CCL to be at 6256.6'. A little tight at 2.813" ID SCSSV at 150' but did not sit down. Continue down hole. CIBP sat down in 3-1/2" tubing at 4780' while
running 150' FPM. Some over pull to free. Sat down gently 3 more times. Could not pass obstruction. Consulted engineer. Located on hand a 2.77" gauge ring,
junk basket & spang jar. Decision made to not risk damage to CIBP & POOH. OOH. No marks or obvious damage to CIBP. Secure well. Change out tool string
to run junk basket. AK E-Line is searching for slim line CIBP if needed. SDFN. Plan forward: Discuss in morning meeting availability of slim line CIBP and
discuss running junk basket / gauge ring to clear obstruction.
n (LAT/LONG):
evation (RKB):
50-283-20189-00-00API #:
Well Name:
Field:
County/State:
BRU 211-35
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
231-00091
$491,320
Job Name:231-00091 BRU 211-35 Completion
Spud Date:
p
Pull CBL log and send to town.
Mobe E-line crew & tools to Beluga
p
Log approved by town. RDMO AK E-line.
M/U 1-11/16" CBL tools
8/12/2023 Morning meeting. PJSM & permit. Travel to location. Gen set not starting. Hook to shore power. R/U AK E-Line. M/U work string consisting of 2) 5' x 1-11/16" 1)
7' x 1-11/16" wt. bars. X-over, Spang jar, junk basket w/ 2.77" Gauge ring. RIH w/ junk basket / 2.77" Gauge ring. Got past previous obstruction at 4780' w/ no
issue. However CCL stopped working. Continued down hole & drifted tubing to just below target depth of CIBP at 6300'. No problems in tubing as w/ 1st run of
full size CIBP. POOH. Lay down junk basket work string. Replace CCL. Decision was made to run Magna Range slim line CIBP at 2.28" OD. M/U setting tool
and CIBP. RIH w/ Magna Range slim line CIBT. Got through trouble spot at 4780' without issue. Continue down hole to setting depth. Made tie in log pass.
Target depth for CIBT is 6268'. CCL to top of plug is 12.4' / CCL will be at 6255.6' to place CIBT at 6268'. Fire setting tool. Good indication of fire on weight
indicator. Sat back down on CIBP after setting tool released to confirm set at 6268'. POOH. OOH. Lay down setting tool. Set up first bailer & mix cement. Pad
Op on location to bleed well down from 2600 to 1600 PSI. RIH w/ 10' x 2.50" dump bailer ONE. Bailer carries 5.3 gallons of cement = 13.5' fill level in 3-1/2"
tubing. Tag top of CIBP at 6282'. Pick up 5'. Arm & fire bailer bailer ONE. Allow time to drain then work bailer up & down to empty cement. TOC now to be at
6254.5'. POOH. OOH. Good fire on Bailer ONE. Redress bailer cap & mix cement to reload bailer. RIH w/ 10' x 2.50" dump bailer TWO. Bailer carries 5.3
gallons of cement = 13.5' fill level in 3-1/2" tubing. Stop at current TOC at 6254.5'. Pick up 5'. Arm & fire bailer bailer TWO. Allow time to drain then work bailer
up & down to empty cement. TOC now to be at 6241'. POOH. OOH. Good fire on Bailer TWO. Redress bailer cap & mix cement to reload bailer. RIH w/ 10' x
2.50" dump bailer THREE. Bailer carries 3 gallons of cement = 8' fill level in 3-1/2" tubing. Stop at current TOC at 6241'. Pick up 5'. Arm & fire bailer bailer
THREE. Allow time to drain then work bailer up & down to empty cement. TOC now to be at 6233'. POOH. OOH. Good fire on Bailer THREE. CIBP is at 6268'
with TOC at 6233' = 35' of cement stacked on CIBP. Lay down lubricator, night cap BOP. Secure well and equipment. SDFN. Plan forward: Re-head rope
socket. Start perforating with H-15 zone.
8/13/2023 PJSM & permit. AK E-Line travel to location. Re-head rope socket. Prep gun FOUR for H 15 zone. Rig back on to well. RIH w/ 25' x 2-3/8" Gun FOUR to shoot H
15 zone. Made tie in pass. Sent log to town for approval. Town approved. Position Gun FOUR. Fire Gun FOUR at H 15 zone 5957' to 5982'. CCL to TS = 9'.
CCL depth to be at 5948' to place TS at 5957'. POOH. Start PSI 1590 / 5 Min 1596 / 10 Min 1597 / 15 Min 1598 / 20 Min 1598 / 25 Min 1599 / 30 Min 1600.
OOH. Lay down Gun FOUR. All shots fired. Pick up Gun FIVE. RIH w/ 25' x 2-3/8" Gun FIVE to shoot H 9 zone lower. Made tie in pass. Sent log to town for
approval. Town approved. Position Gun FIVE. Fire Gun FIVE at H 9 zone lower 5672' to 5697'. CCL to TS = 9'. CCL depth to be at 5563' to place TS at 5672'.
POOH. Start PSI 1803 / 5 Min 1822 / 10 Min 1836 / 15 Min 1850 / 20 Min 1862 / 25 Min 1874 / 30 Min 1887. OOH. Lay down Gun FIVE. All shots fired. Prep
Gun SIX. Pick up Gun SIX. RIH w/ 12' x 2-3/8" Gun SIX to shoot H 9 zone upper. Position Gun SIX. Fire Gun SIX at H 9 zone upper 5660' to 5672'. CCL to TS =
11'. CCL depth to be at 5648' to place TS at 5660'. POOH. Start PSI 2107 / 5 Min 2104 / 10 Min 2102 / 15 Min 2100. Pad Op on location to bleed N2 cap off.
OOH. Lay down Gun SIX. All shots fired. Pad Op has bled N2 off & getting gas returns. Move well to production. AK E-Line secure well and SDFN. Plan forward:
Production to flow test well over night to determine next E-Line runs in morning.
8/14/2023 AK E-Line PJSM & permit. Store spent guns and maintenance. Call in and engineers meet to discuss plan forward. Decision made to run GPT. AK E-Line rig
back on well & set up GPT. RIH w/ 1-11/16" GPT. Log H15 and H9 zones. Sent log to town. Town satisfied zones are dry enough to continue perforating H
zones. POOH w/ GPT. M/U Gun SEVEN / Switch / EIGHT. RIH w/ 6' x 2-3/8" Gun SEVEN for H8 zone / Switch / 20' x 2-3/8" Gun EIGHT for H7 zone. Made tie in
pass log to cover H8 and H7 zones. Send log to town. Town approved. Position Gun SEVEN for H8 zone 5637' to 5643'. CCL to TS = 29' / CCL depth to be
5608' to place TS at 5637'. Fire Gun SEVEN. Start PSI 781 / 5 Min 787 / 10 Min 791 / 15 Min 805. Switch to Gun EIGHT. Position Gun EIGHT for H7 zone 5610'
to 5630'. CCL to TS = 7.5' / CCL depth to be 5602.5' to place TS at 5610'. Fire Gun EIGHT. POOH. Start PSI 811 / 5 Min 796 / 10 Min 790 / 15 Min 782 / 20 Min
772 / 25 Min 836 / 30 Min 894 / 35 Min 982 / 40 Min 1055. Water increase w/ PSI fluctuation. OOH. Water influx had decreased. POOH may have been bringing
water up hole. Laid down Gun SEVEN and EIGHT. P/U Gun NINE and TEN. RIH w/ 6' x 2-3/8" Gun NINE for H6 zone / Switch / 5' x 2-3/8" Gun TEN for H5
zone. Made tie in pass log to cover H6 and H5 Lower zones. Send log to town. Town approved. Position Gun NINE for H6 zone 5555' to 5561'. CCL to TS = 15' /
CCL depth to be 5540' to place TS at 5555'. Fire Gun NINE. Start PSI 822 / 5 Min 818 / 10 Min 819 / 15 Min 817. Switch to Gun TEN. Position Gun TEN for H5
Lower zone 5530' to 5535'. CCL to TS = 8.4' / CCL depth to be 5521.6' to place TS at 5530'. Fire Gun TEN. POOH. Start PSI 817 / 5 Min 817 / 10 Min 812 / 15
Min 799 / 20 Min 786 / 25 Min 775 / 30 Min 879. By time we reached surface PSI had surged to 998. OOH. Laid down Guns NINE and TEN. Secure equipment.
SDFN. Plan forward: Continue perforating H zones.
8/15/2023 AK E-Line PJSM & permit. Travel to location. Rig back on to well. Prep Gun ELEVEN / Switch / TWELVE. RIH w/ 6' x 2-3/8" Gun ELEVEN for upper H5 / Switch
/ Gun TWELVE for H4. Made good tie in pass across H5 and H4 zones but lower switch (Gun ELEVEN) would not verify. POOH to troubleshoot. OOH. Break off
bottom gun ELEVEN. Switch is good but wires were bound up. Made repairs. Reran 6' x 2-3/8" Gun ELEVEN for upper H5 / Switch / 6' x 2-3/8" Gun TWELVE for
H4. Position 6' x 2-3/8" Gun ELEVEN at upper H5 zone 5512' to 5518'. CCL to TS = 15' / CCL depth to be 5497' to place TS at 5512'. Fire gun. Start PSI 768 / 5
Min 780 / 10 Min 784 / 15 Min 786. Switch to Gun TWELVE and position at H4 zone 5493' to 5499'. CCL to TS = 7.5' / CCL to be at 5485.5' to place TS at 5493'.
Fire gun. POOH. Start PSI 787 / 5 Min 786 / 10 Min 771 / 15 Min 756. OOH. Laid down Guns ELEVEN & TWELVE. P/U Guns THIRTEEN & FOURTEEN. RIH w/
20' x 2-3/8" Gun THIRTEEN for H2 / Switch / 6' x 2-3/8" Gun TWELVE for H1. Made tie in pass across H2 & H1 zones. Sent log to town. Town adjusted down by
1'. Made adjustment. Position 20' x 2-3/8" Gun THIRTEEN at H2 zone 5398' to 5418'. CCL to TS = 15' / CCL depth to be 5383' to place TS at 5398'. Fire gun.
Start PSI 813 / 5 Min 810 / 10 Min 798 / 15 Min 789. Switch to 6' x 2-3/8" Gun FOURTEEN and position at H1 zone 5366' to 5372'. CCL to TS = 7.5' / CCL to be
at 5358.5' to place TS at 5366'. Fire gun. POOH. Start PSI 813 / 5 Min 810 / 10 Min 798 / 15 Min 789. OOH. Laid down Guns THIRTEEN & FOURTEEN. Lay
down lubricator and secure well. Prep unit for rig job at Lewis River. SDFN. Plan forward: AK E-Line unit to perform job on rig at Lewis River in morning.
Additional guns for BRU 211-35 G zones will arrive Beluga tomorrow afternoon and perforating will resume when rig job is complete.
8/16/2023 AK E-Line is doing work at Lewis River today. Will resume perforating tomorrow. Guns for G zones are to be here via Otter tomorrow morning as well.
8/17/2023 AK E-Line PJSM & permit. Travel to location. Spot equipment. Re-head. Guns for G zone arrive on Otter. P/U guns and deliver to location. Set up guns and
complete rig up. RIH w/ Gun 15 (6' x 2-3/8") G9 zone / Switch / Gun 16 (5' x 2-3/8") G9 zone. Made tie in pass over entire G zone 5400' up to 4800'. Sent log to
town. Town approved log for all G zone shots. Position Gun 15 (6' x 2-3/8") across G zone 5237' to 5243'. CCL to TS = 15' / CCL to be at 5222' to place TS at
5237' Fire gun. Start PSI 752 / 5 Min 748 / 10 Min 745 / 15 Min 743. Switch. Position Gun 16 (5' x 2-3/8") across G zone 5217' to 5222'. CCL to TS = 7.5' / CCL
to be at 5209.5' to place TS at 5217' Fire gun. POOH. Start PSI 756 / 5 Min 758 / 10 Min 746 / 15 Min 731. Lay down Guns 15 & 16. P/U Gun 17 / Switch / Gun
18. RIH w/ Gun 17 (6' x 2-3/8") G8 zone / Switch / Gun 18 (6' x 2-3/8") G8 zone. Position Gun 17 (6' x 2-3/8") across G8 zone 5204' to 5210'. CCL to TS = 15' /
CCL to be at 5189' to place TS at 5204' Fire gun. Start PSI 813 / 5 Min 812 / 10 Min 813 / 15 Min 812. Gas rate: Start 2370 / Finish 2374. Switch. Position Gun
18 (6' x 2-3/8") across G8 zone 5181' to 5187'. CCL to TS = 7.5' / CCL to be at 5173.5' to place TS at 5181' Fire gun. POOH. Start PSI 813 / 5 Min 819 / 10 Min
815 / 15 Min 806. Gas rate: Start 2377 / Finish 2365. Lay down Guns 17 & 18. P/U Gun 19. RIH w/ Gun 19 (12' x 2-3/8") G6 zone. Position Gun 19 (12' x 2-3/8")
across G6 zone 5143' to 5155'. CCL to TS = 11' / CCL to be at 5132' to place TS at 5143' Fire gun. POOH Start PSI 860 / 5 Min 864 / 10 Min 860 / 15 Min 858.
Gas rate: Start 2570 / Finish 2563. OOH. Lay down Gun 19. P/U Gun 20. RIH w/ Gun 20 (18' x 2-3/8") G5 zone. Position Gun 20 (18' x 2-3/8") across G5 zone
5091' to 5109'. CCL to TS = 11' / CCL to be at 5080' to place TS at 5091' Fire gun. POOH. Start PSI 891 / 5 Min 870 / 10 Min 866 / 15 Min 864. Gas rate: Start
2644 / Finish 2577. OOH. Lay down Gun 20. Secure well. SDFN. Plan forward: Continue perforating G zones.
8/18/2023 AK E-Line PJSM & permit. Travel to location. Rig back on well & prep Gun 21 - G4 zone / Switch / Gun 22 - G3 zone. RIH w/ Gun 21 (6' x 2-3/8") G4 zone /
Switch / Gun 22 (10' x 2-3/8") G3 zone. Position Gun 21 (6' x 2-3/8") across G4 zone at 5069' to 5075'. CCL to TS = 19' / CCL to be at 5050' to place TS at
5069'. Fire gun. Start PSI 765 / 5 Min 769 / 10 Min 767 / 15 Min 765. Gas rate: Start 2966 / End 2946. Switch. Position Gun 22 (10' x 2-3/8") across G3 zone at
5027' to 5037'.CCL to TS = 7.5' / CCL to be at 5019.5' to place TS at 5027'. Fire gun. POOH. Start PSI 765 / 5 Min 764 / 10 Min 763 / 15 Min 755. Gas rate:
Start 2966 / End 2823. OOH. Lay down Gun 21 & Gun 22. P/U Gun 23,RIH w/ Gun 23 (12' x 2-3/8") G3 zone. Position Gun 23 (12' x 2-3/8") across G3 zone at
5005' to 5017'. CCL to TS = 11' / CCL to be at 4994' to place TS at 5005'. Fire gun. POOH. Start PSI 792 / 5 Min 785 / 10 Min 775 / 15 Min 838. Gas rate: Start
3134 / End 3190. OOH. Lay down Gun 23. P/U Gun 24 / Switch / Gun 25. RIH w/ Gun 24 (10' x 2-3/8") G2 zone / Switch / Gun 25 (9' x 2-3/8") G1 zone. Position
Gun 24 (10'' x 2-3/8") across G2 zone at 4979' to 4989'. CCL to TS = 19' / CCL to be at 4960' to place TS at 4979'. Fire gun. Start PSI 783 / 5 Min 777 / 10 Min
764 / 15 Min 758. Gas rate: Start 3024 / End 3042. Switch. Position Gun 25 (9' x 2-3/8") across G1 zone at 4945' to 4954'. CCL to TS = 7.5' / CCL to be at
4937.5' to place TS at 4945'. Fire gun. POOH. Start PSI 776 / 5 Min 773 / 10 Min 764 / 15 Min 758. Gas rate: Start 3044 / End 2984. OOH. Lay down Gun 24 &
Gun 25. Guns for F zone shots to arrive on 4:00 Otter. Maintenance & prep tools. P/U guns for F zones at airport from Otter. Stage on location for morning runs.
Plan forward: Perforating on G zones complete. Moving forward to perforate F zones.
8/19/2023 AK E-Line PJSM & permit. Travel to location. Rig back on well & prep Gun 26 F-10 zone / Switch / Gun 27 F-7 zone. RIH w/ Gun 26 (6' x 2-3/8") F10 zone /
Switch / Gun 27 (14' x 2-3/8") F7 zone. Made tie in pass over entire F zone 4950' up to 4350'. Sent log to town. Town approved. Tie in log will suffice for all F
zone shots. Position Gun 26 (6' x 2-3/8") across F10 zone at 4855' to 4861'. CCL to TS = 23' / CCL to be at 4832' to place TS at 4855'. Fire gun. Start PSI 771 /
5 Min 765 / 10 Min 765 / 15 Min 763. Gas rate: Start 3014 / End 3066. Switch. Position Gun 27 (14' x 2-3/8") across F7 zone at 4797' to 4811'. CCL to TS = 7.5"
/ CCL to be at 4789.5' to place TS at 4797'. Fire gun. POOH. Start PSI 761 / 5 Min 759 / 10 Min 759 / 15 Min 750. Gas rate: Start 3053 / End 2947. OOH. Lay
down Gun 26 & 27. P/U Gun 28 F7 zone / Switch / Gun 29 F7 zone. RIH w/ Gun 28 (10' x 2-3/8") F7 zone / Switch / Gun 29 (12' x 2-3/8") F7 zone. Position Gun
28 (10' x 2-3/8") across F7 zone at 4765' to 4775'. CCL to TS = 23' / CCL to be at 4742' to place TS at 4765'. Fire gun. Start PSI 774 / 5 Min 769 / 10 Min 765 /
15 Min 763. Gas rate: Start 3284 / End 3236. Switch. Position Gun 29 (12' x 2-3/8") across F7 zone at 4731' to 4743'. CCL to TS = 9.4" / CCL to be at 4721.6' to
place TS at 4731'. Fire gun. POOH. Start PSI 769 / 5 Min 765 / 10 Min 754 / 15 Min 747. Gas rate: Start 3236 / End 3176. OOH. Lay down Gun 28 & 29. P/U
Gun 30 F7 / Switch / Gun 31 F6 zone. RIH w/ Gun 30 (10' x 2-3/8") F7 zone / Switch / Gun 31 (5' x 2-3/8") F6 zone. Position Gun 30 (10' x 2-3/8") across F7
zone at 4704' to 4714'. CCL to TS = 15' / CCL to be at 4689' to place TS at 4704'. Fire gun. Start PSI 783 / 5 Min 777 / 10 Min 774 / 15 Min 770. Gas rate: Start
3342 / End 3323. Switch. Position Gun 31 (5' x 2-3/8") across F6 zone at 4682' to 4687'. CCL to TS = 8.5" / CCL to be at 4673.5' to place TS at 4682'. Fire gun.
POOH. Start PSI 770 / 5 Min 765 / 10 Min 757 / 15 Min 747. Gas rate: Start 3323 / End 3231. OOH. Lay down Gun 30 & 31. P/U Gun 32 F6. RIH w/ Gun 32 (12'
x 2-3/8") F6 zone. Position Gun 32 (12' x 2-3/8") across F6 zone at 4629' to 4641'. CCL to TS = 11" / CCL to be at 4618' to place TS at 4629'. Fire gun. POOH.
Start PSI 775 / 5 Min 772 / 10 Min 761 / 15 Min 755. Gas rate: Start 3343 / End 3262. OOH. Lay down Gun 32. P/U Gun 33 F6. RIH w/ Gun 33 (8' x 2-3/8") F6
zone. Position Gun 33 (8' x 2-3/8") across F6 zone at 4605' to 4613'. CCL to TS = 11" / CCL to be at 4594' to place TS at 4605'. Fire gun. POOH. Start PSI 790 /
5 Min 786 / 10 Min 777 / 15 Min 775. Gas rate: Start 3334 / End 3297. OOH. Lay down Gun 33. P/U Gun 34 F5. RIH w/ Gun 34 (6' x 2-3/8") F5 zone. Position
Gun 34 (6' x 2-3/8") across F5 zone at 4576' to 4582'. CCL to TS = 9.2" / CCL to be at 4566.8' to place TS at 4576'. Fire gun. POOH. Start PSI 789 / 5 Min 782 /
10 Min 773 / 15 Min 767. Gas rate: Start 3321 / End 3246. OOH. Lay down Gun 34. P/U Gun 35 F5. RIH w/ Gun 35 (6' x 2-3/8") F5 zone. Position Gun 35 (6' x 2-
3/8") across F5 zone at 4556' to 4562'. CCL to TS = 9.2" / CCL to be at 4546.8' to place TS at 4556'. Fire gun. POOH. Start PSI 790 / 5 Min 783 / 10 Min 775 /
15 Min 768. Gas rate: Start 3327 / End 3245. OOH. Lay down Gun 35. P/U Gun 36 F5. RIH w/ Gun 36 (8' x 2-3/8") F5 zone. Position Gun 36 (8' x 2-3/8") across
F5 zone at 4545' to 4553'. CCL to TS = 11" / CCL to be at 4534' to place TS at 4545'. Fire gun. POOH. Start PSI 784 / 5 Min 776 / 10 Min 769 / 15 Min 774. Gas
rate: Start 3375 / End 3223. OOH. Lay down Gun 36. P/U Gun 37 F4. RIH w/ Gun 37 (13' x 2-3/8") F4 zone. Position Gun 37 (13' x 2-3/8") across F4 zone at
4505' to 4518'. CCL to TS = 10" / CCL to be at 4495' to place TS at 4505'. Fire gun. POOH. Start PSI 786 / 5 Min 780 / 10 Min 770 / 15 Min 761. Gas rate: Start
3324 / End 3221. OOH. Lay down Gun 37. P/U Gun 38 F1. RIH w/ Gun 38 (9' x 2-3/8") F1 zone. Position Gun 38 (9' x 2-3/8") across F1 zone at 4443' to 4452'.
CCL to TS = 10" / CCL to be at 4433' to place TS at 4443'. Fire gun. POOH. Start PSI 780 / 5 Min 772 / 10 Min 769 / 15 Min 771. Gas rate: Start 3294 / End
3198. OOH. Lay down Gun 38. Perforating of F zones complete. Partial rig down. Well is capped and secure. SDFN. Plan forward: Complete rig down BRU 211-
35. Move to BRU 212-26 for GPT.
1
Regg, James B (OGC)
From:Brooks, Phoebe L (OGC)
Sent:Tuesday, August 22, 2023 3:44 PM
To:Joshua Riley - (C)
Cc:Regg, James B (OGC)
Subject:RE: MIT-T BRU211-35 7-24-23 Revised
Attachments:MIT BRU 211-35 07-24-23 Revised.xlsx
Josh,
Attached is a revised report moving the “waived by” verbiage to the Notes and revised the second test notes to MIT‐IA.
Please update your copy or let me know if you disagree.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907‐793‐1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Joshua Riley ‐ (C) <jriley@hilcorp.com>
Sent: Tuesday, July 25, 2023 5:11 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>;
Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Subject: MIT‐T BRU211‐35 7‐24‐23 Revised
Apologies I fat fingered the IA pressure test numbers
Josh Riley
Hilcorp DSM: 907-283-1369
Cell: 907-252-1211
Hilcorp Alaska, LLC
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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Beluga River Unit 211-35PTD 2230500
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230500 Type Inj G Tubing 0 3620 3600 3600 Type Test P
Packer TVD 2589 BBL Pump 0.8 IA 0 20 20 20 Interval O
Test psi 3500 BBL Return 0.8 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230500 Type Inj G Tubing 0 280 280 280 Type Test P
Packer TVD 2589 BBL Pump 1.1 IA 0 2630 2620 2620 Interval O
Test psi 2500 BBL Return 1.0 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:MIT-IA as per post completion PTD. Jim Regg Waived Winess of MIT
Notes:
Notes:
Hilcorp Alaska LLC.
Beluga River Unit E pad
Joshua Riley
07/24/23
Notes:MIT-T as per post completion PTD. Jim Regg Waived Winess of MIT
Notes:
Notes:
Notes:
211-35
211-35
Form 10-426 (Revised 01/2017)2023-0724_MITP_BRU_211-35_2tests
==N
J. Regg; 10/12/2023
Well is a gas producer
===N
David Douglas Hilcorp Alaska, LLC Rd, -3- C),Sz:)
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
ThIr„rp +tlayka, LIA E-mail: david.douglas@hilcorp.com
Date: 08/11/2023
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 211-35
- PTD 223-050
- API 50-283-20189-00-00
Washed and Dried Well Samples (07/13/2023)
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 211-35
BOX 1 OF 3
2700' - 4440' MD
BRU 211-35
BOX 2 OF 3
4440' - 6120' MD
BRU 211-35
BOX 3 OF 3
6120' — 7199' MD
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received Date:
RECEIVED
A116 11 2023
AOGCC
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: 08/08/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 211-35
- PTD 223-050
- API 50-283-20189-00-00
MUDLOGS - EOW DRILLING REPORTS (06/28/2023 to 07/13/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log
Drilling Dynamics Log
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-050
T37918
8/9/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.09
08:49:12 -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: 8/03/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 211-35
- PTD 223-050
- API 50-283-20189-00-00
FINAL LWD FORMATION EVALUATION LOGS (06/28/2023 to 07/13/2023)
EWR-M5, AGR, PCG, ADR, ALD, CTN, ROP (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
FINAL GEOTAP FORMATION PRESSURE TESTER (06/28/2023 to 07/13/2023)
Color Time Log Presentations
Final Report
Digital LAS Data Files
Folder Contents:
Please include current contact information if different from above.
PTD: 223-050
T37909
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.03
12:04:15 -08'00'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 211-35
JBR 09/05/2023
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
3-1/2" & 4-1/2" joints. Choke HCR cycled for a pass.
Test Results
TEST DATA
Rig Rep:Porterfield/TrickOperator:Hilcorp Alaska, LLC Operator Rep:Murphy/Richardson
Rig Owner/Rig No.:Hilcorp 147 PTD#:2230500 DATE:7/14/2023
Type Operation:DRILL Annular:
250/3500Type Test:BIWKLY
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopSAM230716144136
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
2356
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
13 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"P
#1 Rams 1 2-7/8"x5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 2-1/16&3-1/8 FP
Kill Line Valves 3 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1650
200 PSI Attained P21
Full Pressure Attained P85
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2600
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 P5
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9999
9
9
9FP
Choke HCR
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,199'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
N/A N/A
6,938'7,132'6,871'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 211-35CO 802
Same
6,936'3-1/2"
~2270psi
4,640'
N/A
Length
July 28, 2023
Tieback 3-1/2"
7,197'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
2,785'
Size
120'
2,785'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
2,557'
10,160psi
2,565'
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
223-050
50-283-20189-00-00
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
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 3:27 pm, Jul 14, 2023
323-400
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.07.14 15:06:12 -
08'00'
Noel Nocas
(4361)
MDG 7/18/2023
10-407
BJM 7/21/23
DSR-7/19/23
Submit CBL to AOGCC for review and obtain approval before perforating.
JLC 7/21/2023
07/21/23
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.07.21
15:31:12 -05'00'
RBDMS JSB 072523
Well Prognosis
Well Name: BRU 211-35 API Number: 50-283-20189-00-00
Current Status: Gas Producer Permit to Drill Number: 223-050
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O)
Maximum Expected BHP: 2937 psi @ 6677’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2270 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 211-35 is the second of five grass roots wells 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 and perforate
multiple Beluga sands. All sands lie in the Sterling Beluga Gas Pool.
Wellbore Conditions:
Drilling will leave the cemented 4.5” liner full of drilling mud, with the 4.5” tubing and annulus displaced to KCL,
and pressure tested.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 2500 psi. higher test pressure to accommodate reverse out
4. Clean out wellbore to TD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, PT lubricator to 2500psi, log CBL submit CBL to AOGCC for review
6. RIH, reverse out wellbore with nitrogen, trap ~1700 psi on wellbore
7. RDMO coil tubing
8. RU E-line, PT lubricator to 2500 psi
9. Perforate and test Beluga sands within the below interval from the bottom up:
Sand MD TVD
Top Sand Beluga F 4694’ 4459’
Bottom Sand Beluga J 6930’ 6677’
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 13.9 ppg EMW FIT at the surface casing shoe (0.722 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.722-0.1) = 2270 psi / 0.622 = 3650‘ TVD
10. RDMO
11. Turn well over to production & flow test well
Well Prognosis
Attachments:
1. As-built Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
5. AOGCC RWO Change Form
Updated by DMA 07-14-23
SCHEMATIC
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,132’ MD / TVD = 6,871’
TD = 7,199’ MD / TVD = 6,938’
RKB to GL = 18.5’
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (50% excess)
3-1/2” Est. TOC @ TOL (40% excess)
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 2,785’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,557’ 7,197’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,557’
1
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,595’ 4.875” 6.540” Seal Stem, Liner hanger / LTP Assembly
2 ~1,500’ 2.813” 3.500” Chemical Injection Sub
3 ~150’ 2.813” 5.565” SSSV
6-3/4”
hole
2
3
Updated by DMA 07-14-23
PROPOSED
Beluga River Unit
BRU 211-35
PTD: 223-050
API: 50-283-20189-00-00
PBTD = 7,132’ MD / TVD = 6,871’
TD = 7,199’ MD / TVD = 6,938’
RKB to GL = 18.5’
Bel F – Bel J
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (50% excess)
3-1/2” Est. TOC @ TOL (40% excess)
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 2,785’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,557’ 7,197’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,557’
1
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,595’ 4.875” 6.540” Seal Stem, Liner hanger / LTP Assembly
2 ~1,500’ 2.813” 3.500” Chemical Injection Sub
3 ~150’ 2.813” 5.565” SSSV
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
Bel F-J ±4,694’ ±6,930’ ±4,459’ ±6,677’ Proposed TBD
6-3/4”
hole
2
3
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.
Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BRU 211-35 (PTD 223-050) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date
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 Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Beluga River, Sterling-Beluga Gas Pool, BRU 211-35
Hilcorp Alaska, LLC
Permit to Drill Number: 223-050
Surface Location: 1306’ FNL, 800’ FWL, Sec 35, T13N, R10W, SM, AK
Bottomhole Location: 86' FSL, 127' FWL, Sec 35, T13N, R10W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie Chmielowski
Commissioner
DATED this ___ day of June 2023. 21
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.06.21 13:05:51
-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: 7,199' TVD: 6,938'
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): 99.6' 15. Distance to Nearest Well Open
Surface: x-318707 y- 2623842 Zone-4 81.1' to Same Pool:1158' to BRU 244-27
16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 28 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 TXP 2,795' Surface Surface 2,795' 2,575'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,604' 2,595' 2,385' 7,199' 6,938'
Tieback 3-1/2" 9.2# L-80 Hyd 563 2,595' Surface Surface 2,595' 2,385'
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
7/1/2023
5408' 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 - 927 ft3 / T - 209 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
1474
18. Casing Program:Top - Setting Depth - BottomSpecifications
3050
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 - 1061 ft3 / T - 131 ft3
2356
485' FNL, 248' FWL, Sec 35, T13N, R10W, SM, AK
86' FSL, 127' FWL, Sec 35, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1306’ FNL, 800’ FWL, Sec 35, T13N, R10W, SM, AK A029657
BRU 211-35
Beluga River Unit
Sterling - Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
s
D
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
6.6.2023
By Grace Christianson at 1:19 pm, Jun 06, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.06.06 11:50:08 -08'00'
Monty M
Myers
SFD 6/14/2023BJM 6/20/23
DSR-6/12/23
50-283-20189-00-00223-050
BOP test to 3500 psi. Annular test to 2500 psi.
Submit FIT/LOT data to AOGCC within 24 hrs of obtaining data.
GCW 06/20/2023
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2023.06.21 13:06:07 -08'00'
BRU 211-35
Drilling Program
Beluga River Unit
Rev 0
May 27, 2023
BRU 211-35
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 3-1/2” Production Liner ...................................................................................................26
17.0 Cement 3-1/2” Production Liner .............................................................................................29
18.0 3-1/2” Liner Tieback Polish Run .............................................................................................32
19.0 3-1/2” 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-Staked NAD27 & NAD83)...........................................................................47
Page 2 Version 0 April, 2023
BRU 211-35
Drilling Procedure
Rev 0
1.0 Well Summary
Well BRU 211-35
Pad & Old Well Designation BRU E Pad –Grassroots Well
Planned Completion Type 3-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7,199 MD / 6,938’ TVD
PBTD, MD / TVD 7,119’ MD / 6,858’TVD
Surface Location (Governmental)1306’ FNL, 800’ FWL, Sec 35, T13N, R10W, SM, AK
Surface Location (NAD 27)X=318707.90 Y=2623842.80
Surface Location (NAD 83)X=1458738.70 Y=2623596.50
Top of Productive Horizon
(Governmental)485' FNL, 248' FWL, Sec 35, T13N, R10W, SM, AK
TPH Location (NAD 27)X=318172, Y=2624666
TPH Location (NAD 83)X=1458199 Y=2624426
BHL (Governmental)86' FSL, 127' FWL, Sec 35, T13N, R10W, SM, AK
BHL (NAD 27)X=318060, Y=2625239
BHL (NAD 83)X=1458087 Y=2624999
AFE Number
AFE Drilling Days 25
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2356 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3050 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 99.6’(81.1 + 18.5)
Ground Elevation 81.1’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 0 April, 2023
BRU 211-35
Drilling Procedure
Rev 0
2.0 Management of Change Information
Page 4 Version 0 April, 2023
BRU 211-35
Drilling Procedure
Rev 0
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”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
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
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
Page 5 Version 0 April, 2023
BRU 211-35
Drilling Procedure
Rev 0
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area –this will not save the data entered, and will navigate to another data entry
tab.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a
username to login with.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
BRU 211-35 is an S-shaped directional grassroots development well to be drilled from BRU E 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 ~28 deg. and TD of the well will be 7,199’ TMD/ 6,938’ TVD, ending with 7 deg inclination left in
the hole. Vertical section will be 1539 ft.
Drilling operations are expected to commence approximately July 1
st, 2023. The Hilcorp Rig # 147 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 2,795 MD / 2,575’ 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 2,795’ 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 7,199’MD. Perform Wiper trip.
6. Make cleanout run
7. POOH laying down drill pipe.
8. Run and cmt 3-1/2”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 Pressures dependent on hole conditions
Mud loggers from surface casing point to TD.
3-1/2" -bjm
3-1/2" -bjm
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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 211-35. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs. And BLM 72 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.
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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.
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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
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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 Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line
up with flowline later.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 RU Mud loggers on surface hole section for gas detection only. No samples required
9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.9 Mix mud for 9-7/8”hole section.
9.10 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” 2M Diverter
10.1 N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE: Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
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10.5 Rig 147 and estimated Diverter line orientation on BRU F 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 2,795’MD/ 2,575’ 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 2700’ MD and 2900’ 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
120-2795’ 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:
(2295’ –120’) x .03825 bpf x
1.75 =
145.59 817.4
Total LEAD:165.08 bbl 926.8 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(2795’- 2295’)x .03825 bpf x
1.5 =
33.47 187.9
15.4 ppg TAIL:
7-5/8”Shoe track:
80 x .04592 bpf =3.67 20.6
Total TAIL:37.14 bbl 208.5 ft3
TOTAL CEMENT VOL:202.22 bbl 1135.3 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:
2795’-80’ = 2715’x .04592 bpf = 125 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 (2295’ MD to surface)Tail Slurry (2795’ to 2295’ 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
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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 and BLM.
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14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Run BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min.
x Test with 4-1/2” and 3-1/2” test joints.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.0 ppg 6% KCL PHPA mud system.
14.8 R/U mud loggers for production hole section.
14.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
2,795’-7,199’9.0 –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 13.8 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 13.8 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 7,199’ MD / 6,938’ 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 5,000’ 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 (3,825-4,403’ 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’.
Agree. -bjm
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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 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 3-1/2” test joint.
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16.0 Run 3-1/2”Production Liner
16.1. R/U Weatherford 3-1/2”casing running equipment.
x Ensure 3-1/2”HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint 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 3-1/2” production liner
3-1/2” 9.2# HYD 563 M/U torques
Casing OD Minimum Maximum Yield
3-1/2”2,400 ft-lbs 4,200 ft-lbs 7,100 ft-lbs
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16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 3-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
16.15. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom.
Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the
shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and
thinners.
16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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17.0 Cement 3-1/2”Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
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 3-1/2” liner
annulus:
200’ x .03402 bpf =6.80 38.2
12.0 ppg LEAD:
6-3/4” OH x 3-1/2” annulus:
(6699’ –2795’) x .03236 bpf x
1.4 =
176.87 993.1
Total LEAD:188.92 bbl 1060.8 ft3
15.4 ppg TAIL:
6-3/4” OH x 3-1/2” annulus:
(7199’- 6699’) x .03236 bpf x
1.4 =
22.65 127.2
15.4 ppg TAIL:
3-1/2” Shoe track:
80 x .00870 bpf =0.70 3.9
Total TAIL:23.35 bbl 131.1 ft3
TOTAL CEMENT VOL:212.27 bbl 1191.9 ft3
Verified cement calcs. -bjm
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Cement Slurry Design:
Lead Slurry (6690’ MD to 2395’ MD)Tail Slurry (7199’ to 6699’ 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 and BLM.
18.0 3-1/2”Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, and LDDP and polish mill.
x NOTE: If a cleanout run inside the 3-1/2” is needed, BOPs need to be tested with test joint to
cover cleanout assembly.
18.4. If not completed, test 3-1/2” casing to 3,500 psi and chart for 30 minutes
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19.0 3-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 4-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 HYD 563 casing.
x Install Chemical injection mandrel at ~1500’. OD should be 5.9”
x Install SSSV at ~150’ in tieback string.
o Dual control line spooler needed
3-1/2” 9.2# HYD 563 M/U torques
Casing OD Minimum Maximum Yield
3-1/2”2,400 ft-lbs 4,200 ft-lbs 7,100 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. 72 hr notice required.
19.7 Test 7-5/8” x 4-1/2” annulus to 2,500 psi and chart for 30 minutes. 72 hr notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO Hilcorp Rig #147
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20.0 Diverter Schematic
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21.0 BOP Schematic
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22.0 Wellhead Schematic
3-1/2"
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23.0 Days Vs Depth
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24.0 Geo-Prog
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25.0 Anticipated Drilling Hazards
9-7/8”Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 –45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
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.
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26.0 Hilcorp Rig 147 Layout
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Drilling Procedure
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27.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
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28.0 Choke Manifold Schematic
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29.0 Casing Design Information
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30.0 6-3/4” Hole Section MASP
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31.0 Spider Plot w/ 660’ Radius for SSSV
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32.0 Surface Plat (As-Staked NAD27 & NAD83)
!""#
$%
&
'
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500True Vertical Depth (1000 usft/in)-1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500
Vertical Section at 334.00° (1000 usft/in)
BRU 211-35 wp06 tgt1
7 5/8" x 9-7/8"
4 1/2" x 6-3/4"
5 0 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 00 0
3 5 0 0
4 0 0 0
4 50 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 1 9 9
BRU 211-35 wp06
Start Dir 4º/100' : 250' MD, 250'TVD
End Dir : 956.89' MD, 928.55' TVD
Start Dir 2º/100' : 2172.06' MD, 1998.71'TVD
End Dir : 3267.29' MD, 3036.95' TVD
Total Depth : 7199.43' MD, 6938' TVD
BRU_ST_A1_COAL
STERLING_B
STERLING_C
BELUGA_D
BELUGA_E
BELUGA_F
BELUGA_G
BELUGA_H
BELUGA_I
BRU_BELUGA_J
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: BRU 211-35
81.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2623842.80 318707.90 61° 10' 39.8328 N 151° 1' 37.5502 W
SURVEY PROGRAM
Date: 2023-05-31T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2795.00 BRU 211-35 wp06 (BRU 211-35) 3_MWD+AX+Sag
2795.00 7199.43 BRU 211-35 wp06 (BRU 211-35) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3042.60 2943.00 3272.98 BRU_ST_A1_COAL
3249.60 3150.00 3481.63 STERLING_B
3399.60 3300.00 3632.83 STERLING_C
3590.60 3491.00 3825.35 BELUGA_D
3798.60 3699.00 4035.01 BELUGA_E
4164.60 4065.00 4403.93 BELUGA_F
4675.60 4576.00 4919.00 BELUGA_G
5051.60 4952.00 5298.00 BELUGA_H
5792.60 5693.00 6044.90 BELUGA_I
6355.60 6256.00 6612.39 BRU_BELUGA_J
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 211-35, True North
Vertical (TVD) Reference:RKB As-Staked @ 99.60usft (147)
Measured Depth Reference:RKB As-Staked @ 99.60usft (147)
Calculation Method: Minimum Curvature
Project:Beluga River
Site:BRU E-Pad
Well:BRU 211-35
Wellbore:BRU 211-35
Design:BRU 211-35 wp06
CASING DETAILS
TVD TVDSS MD Size Name
2574.66 2475.06 2795.00 7-5/8 7 5/8" x 9-7/8"
6938.00 6838.40 7199.43 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
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 4º/100' : 250' MD, 250'TVD
3 956.89 28.28 325.48 928.55 140.82 -96.86 4.00 325.48 169.03 End Dir : 956.89' MD, 928.55' TVD
4 2172.06 28.28 325.48 1998.71 615.10 -423.09 0.00 0.00 738.32 Start Dir 2º/100' : 2172.06' MD, 1998.71'TVD
5 3267.29 7.21 350.00 3036.95 900.00 -584.00 2.00 171.97 1064.92 BRU 211-35 wp06 tgt1 End Dir : 3267.29' MD, 3036.95' TVD
6 7199.43 7.21 350.00 6938.00 1386.01 -669.70 0.00 0.00 1539.31 Total Depth : 7199.43' MD, 6938' TVD
0
75
150
225
300
375
450
525
600
675
750
825
900
975
1050
1125
1200
1275
1350
1425
South(-)/North(+) (150 usft/in)-825 -750 -675 -600 -525 -450 -375 -300 -225 -150 -75 0 75 150
West(-)/East(+) (150 usft/in)
BRU 211-35 wp06 tgt1
7 5/8" x 9-7/8"
4 1/2" x 6-3/4"
250
5 0 0
7 5 0
1 0 0 0
1 2 5 0
1 5 0 0
1 7 5 0
2 0 0 0
2 2 5 0
2 5 0 0
2 7 5 0
3 0 0 0
32 5 0
3 5 0 0
3 7 5 0
4 0 0 0
4 2 5 0
4 5 0 0
4 7 5 0
5 0 0 0
5 2 5 0
5 5 0 0
5 7 5 0
6 0 0 0
6 2 5 0
6 5 0 0
6 7 5 0
7 0 0 0
7 1 9 9BRU 2 1 1 -3 5 w p 0 6
Start Dir 4º/100' : 250' MD, 250'TVD
End Dir : 956.89' MD, 928.55' TVD
Start Dir 2º/100' : 2172.06' MD, 1998.71'TVD
End Dir : 3267.29' MD, 3036.95' TVD
Total Depth : 7199.43' MD, 6938' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2574.66 2475.06 2795.00 7-5/8 7 5/8" x 9-7/8"
6938.00 6838.40 7199.43 4-1/2 4 1/2" x 6-3/4"
Project: Beluga River
Site: BRU E-Pad
Well: BRU 211-35
Wellbore: BRU 211-35
Plan: BRU 211-35 wp06
WELL DETAILS: BRU 211-35
81.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2623842.80 318707.90 61° 10' 39.8328 N 151° 1' 37.5502 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 211-35, True North
Vertical (TVD) Reference:RKB As-Staked @ 99.60usft (147)
Measured Depth Reference:RKB As-Staked @ 99.60usft (147)
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:BRU 211-35 NAD 1927 (NADCON CONUS)Alaska Zone 0481.10+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002623842.80 318707.90 61° 10' 39.8328 N 151° 1' 37.5502 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 211-35, True NorthVertical (TVD) Reference: RKB As-Staked @ 99.60usft (147)Measured Depth Reference:RKB As-Staked @ 99.60usft (147)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2023-05-31T00:00:00 Validated: Yes Version: Depth From Depth ToSurvey/PlanTool18.50 2795.00 BRU 211-35 wp06 (BRU 211-35) 3_MWD+AX+Sag2795.00 7199.43 BRU 211-35 wp06 (BRU 211-35) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 7199.43Project: Beluga RiverSite: BRU E-PadWell: BRU 211-35Wellbore: BRU 211-35Plan: BRU 211-35 wp06CASING DETAILSTVD TVDSS MD Size Name2574.66 2475.06 2795.00 7-5/8 7 5/8" x 9-7/8"6938.00 6838.40 7199.43 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 nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-050
STERLING-BELUGA GAS
BRU 211-35
BELUGA RIVER
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 211-35Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230500BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes Entire Well lies within ADL0029657.2 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, STRLG-BELUGA GAS - 92500 - governed by 8024 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2356, BOP rated to 5000 psi (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 shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes None expected35 Permit can be issued w/o hydrogen sulfide measuresYes Expected Pressure Range is 0.12 to 0.44 psi/ft (2.3 to 8.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA Lost Circulation: some risk; LCM available onsite; see p. 42.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/14/2023ApprBJMDate6/21/2023ApprSFDDate6/14/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 6/21/2023
