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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,490' N/A
Casing Collapse
Structural
Conductor
Surface 1,950psi
Intermediate
Production 3,090psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; N/A 2,691' MD/TVD; N/A, N/A
6,729' 6,780' 6,031'
Beaver Creek Beluga Gas
20"
13-3/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beaver Creek Unit (BCU) 11ACO 237D
Sterling Gas
6,728'3-1/2"
~1930psi
4,798'
See Schematic
Length
October 24, 2025
Tieback 3-1/2"
7,489'
Perforation Depth MD (ft):
2,898' TOW
See Attached Schematic
3,450psi
2,898'
112'
2,198'
Size
112'
9-5/8"2,898'
2,187'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
2,723'
5,750psi
2,198'
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
AKA 028083
224-123
50-133-20521-01-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Ryan LeMay, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
ryan.lemay@hilcorp.com
661-487-0871
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
325-635
By Gavin Gluyas at 9:22 am, Oct 16, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.10.14 16:12:03 -
08'00'
Noel Nocas
(4361)
BJM 10/20/25 DSR-10/16/25
10-404
X
Provide 24 hrs notice for opportunity to witness TOC tag and pressure test. If testing with liquid, test to
1700 psi. If testing with gas, test to 3000 psi to place > 1000 psi differential across plug. Verify that
completion is designed to withstand this test pressure before testing.
TS 10/21/25
10/22/25
Well Prognosis
Well: BCU-11A
Well Name: BCU-11A API Number: 50-133-20521-01-00
Current Status: Gas Producer Permit to Drill Number: 224-123
Regulatory Contact: Donna Ambruz (907) 777-8305
First Call Engineer: Ryan LeMay (661)487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506 (O)
Maximum Expected BHP: 2514 psi @ 5846 TVD Based on 0.43 psi/ft
Max. Potential Surface Pressure: 1930 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: 0.728 psi/ft using 14.0 ppg EMW FIT at 9-5/8 shoe
Shallowest Allowable Perf TVD: MPSP / (0.728 - 0.1) = 1930 psi / 0.628 = 3074 TVD
Top of Applicable Gas Pool / PA: Beluga Gas Pool / PA 6601 MD / 5855 TVD
Sterling Gas Pool / PA 5546 MD / 4862 TVD
Well Status: Gas Producer
40 mcfd / 50 bwpd / 65 psi FTP as of 10/2/2025
Recent Well Summary:
BCU 11A was a sidetrack well (parent wellbore BCU 11) drilled in late 2024 and initially completed through
January 2025. The well was initially perforated from the Bel 12 through Bel 7 sands. The Bel 12 through lower
Bel 7 sands proved to be unsuccessful. The Bel 7 interval from 6761 6767 MD was successful, and initial
production came on 489 mcfd / 0 bwpd / 79 psi FTP. The well gradually declined to 101 mcfd / 0 bwpd / 65 psi
FTP by August 2025. In September 2025, (4) additional intervals were perforated in the Bel 7 5 sands. Post
perforations the well reduced in rate to 40 mcfd / 50 bwpd / 65 psi FTP as of 10/2/2025.
The objective of this Sundry is to plug and isolate the Beluga gas pool / PA and add up to (6) intervals in the
Sterling Gas Pool / PA from the Sterling A2 B3L sands.
Procedure:
1. MIRU N2 Unit and E-line.
2. Push fluid away with N2 through existing perforations.
3. PT lubricator to 250 psi low / 2,500 psi high
4. RIH and set 3-1/2 CIBP at + 6650.
a. BLM regulations require CIBP to be set within 50 100 of top of open perforations. Hilcorp
requests a variance to BLM regulation CFR 3172.12.(a).(2).(i) setting CIBP at + 6650 (17 above
top perforation due to proximity of lowermost proposed Sterling perforation interval and to allow
necessary room to dump bail regulatory required amount of cement on top of CIBP.
5. Dump bail a minimum of 35 of cement on top of CIBP leaving TTOC at + 6615.
6. Tag TOC w/ E-line and pressure test CIBP + cement to verify plug placement and integrity for Beluga
Gas Pool / PA isolation.
a. Provide a minimum of 24 hr notice to AOGCC for witness of tag and pressure test
b. If fluid is used for pressure test, pressure test to 2500 psi for 30 min (chart results using a chart
recorder or digital crystal gauge)
c. If gas is used for pressure test to 2500 psi
i. Use a chart recorder or digital crystal gauge monitor for a minimum of 72 hours
ii. Criteria for a passing test being a time of 72 hours showing stabilization and less than
2% drop of the maximum test pressure over the 72 hour test period.
iii. IA pressure must be monitored over the duration of the test period.
iv. 72 hour test will start once pressure stabilizes.
Well Prognosis
Well: BCU-11A
7. RIH and perforate the following sands:
Well Sand Top MD Btm MD Top TVD Btm TVD Interval
BCU-11A Sterling B3L ±5,818 ±5,826 ±5,100' ±5,107' ±8'
BCU-11A Sterling B3L ±5,882 ±5,886 ±5,159 ±5,162 ±4
BCU-11A Sterling B5 ±5,939 ±5,942 ±5,211' ±5,214' ±3'
BCU-11A Sterling B5 ±5,978 ±5,984 ±5,248' ±5,254' ±6'
BCU-11A Sterling B6 ±6,002 ±6,017 ±5,271' ±5,285' ±15'
BCU-11A Sterling A1 ±6,538 ±6,549 ±5,793' ±5,803' ±11'
BCU-11A Sterling A2 ±6,578 ±6,592 ±5,832' ±5,846' ±14'
a. Correlate using log provided by Geologist. Send the correlation pass to the Operations
Engineer, Reservoir Engineer, and Geologist for confirmation
b. Use Gamma/CCL to correlate
c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min
intervals post perf shot (if using switched guns, wait 10 min between shots)
d. Pending well production, all perf intervals may not be completed
e. If any current or proposed zones produce sand and/or water or needs isolated, RIH and set
plug above the perforations OR patch across the perforations
i. Note: A CIBP may be used instead of WRP if it is determined that no cement is
needed for operational purposes. 35ft will not be placed on each plug as these
zones are close together. If possible, the CIBP will be set 50 above of the top of
the last perforated sand unless zones are too close together in which case the plug
will be set within 50.
f. If necessary, use nitrogen or pad gas throughout operations to pressure up well during
perforating or to depress water prior to setting a plug above perforations.
8. RDMO and turn well over to production ops.
Contingency Procedure: Coiled Tubing Cleanout
1. If throughout the job any current or proposed zones produce sand and / or water that cannot be
depressed and pushed away with nitrogen or pad gas, a coil tubing unit may be rigged up to clean out
fill or fluid blown down as necessary.
a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high
i. Provide AOGCC 24hrs notice of BOP test.
b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary.
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Coil Tubing BOP Diagram
4. Standard Well Procedure N2 Operations
_____________________________________________________________________________________
Updated by RPL 9-27-2025
Schematic Beaver Creek Unit
Well: BCU-11A
PTD: 224-123
API: 50-133-20521-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20"Conductor 133 / K-55 / -19Surf 112
13-3/8Surface 68 / K-55 / BTC 12.515Surf 2,198
9-5/8" Intermediate 40 / L-80 / BTC 8.835Surf 2,898
(TOW)
3-1/2Prod Liner 9.2 / L-80 / HYD-563 2.9912,6917,489
3-1/2Tieback 9.3 / L-80 / EUE 8Rd 2.991Surf 2,723
OPEN HOLE / CEMENT DETAIL
20Driven
13-3/8TOC @ Surface 820 sx
9-5/8" TOC @ Surface 1129 sx
3-1/2 TOC @ 2704 (CBL 11/9/24) L 201 bbls / T - 24 bbls
JEWELRY DETAIL
No. Depth Item
1 1,346Chemical Inj sub
2 2,691Liner Top Packer
3 2,723Seal Assembly
4 6,780CIBP (1/19/24)
5 6,830CIBP (1/15/25)
6 6,850CIBP (11/30/24)
7 6,890CIBP (11/29/24)
8 7,188CIBP (11/20/24)
9 7,225CIBP (11/18/24)
10 7,380CIBP (11/17/24)
PERFORATION DETAIL
Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status
Bel 5 6,667 6,6755,920' 5,927' 8'9/24/25 Open
Bel 6 6,726 6,7325,978' 5,984' 6'9/24/25 Open
Bel 7 6,745 6,7495,996' 6,000' 4'9/23/25 Open
Bel 7 6,752 6,7566,003' 6,007' 4'9/23/25 Open
Bel 7 6,7616,7676,0126,01861/19/25 Open
Bel 7 6,7846,7906,0356,04161/17/24 Isolated
Bel 8 6,8346,8446,0856,0951012/1/24 Isolated
BEL 8 6,854'6,864'6,105'6,115'1011/30/24 Isolated
BEL 8C 6,898'6,908'6,148'6,158'10'11/21/24 Isolated
BEL 8D 6,940'6,950'6,188'6,198'10'11/20/24 Isolated
BEL 11 7,195'7,215'6,441'6,460'20'11/19/24 Isolated
BEL 11 7,228'7,234'6,472'6,478'611/18/24 Isolated
BEL 12 7,303'7,309'6,546'6,552'6'11/18/24 Isolated
BEL 12 7,384'7,391'6,625'6,631'6'11/16/24 Isolated
_____________________________________________________________________________________
Updated by RPL 9-30-2025
Schematic
Proposed
Beaver Creek Unit
Well: BCU-11A
PTD: 224-123
API: 50-133-20521-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20"Conductor 133 / K-55 / -19Surf 112
13-3/8Surface 68 / K-55 / BTC 12.515Surf 2,198
9-5/8" Intermediate 40 / L-80 / BTC 8.835Surf 2,898
(TOW)
3-1/2Prod Liner 9.2 / L-80 / HYD-563 2.9912,6917,489
3-1/2Tieback 9.3 / L-80 / EUE 8Rd 2.991Surf 2,723
OPEN HOLE / CEMENT DETAIL
20Driven
13-3/8TOC @ Surface 820 sx
9-5/8" TOC @ Surface 1129 sx
3-1/2 TOC @ 2704 (CBL 11/9/24) L 201 bbls / T - 24 bbls
JEWELRY DETAIL
No. Depth Item
1 1,346Chemical Inj sub
2 2,691Liner Top Packer
3 2,723Seal Assembly
4 +6,650CIBP + 35 cmt (ETOC = 6615) Proposed
5 6,780CIBP (1/19/24)
6 6,830CIBP (1/15/25)
7 6,850CIBP (11/30/24)
8 6,890CIBP (11/29/24)
9 7,188CIBP (11/20/24)
10 7,225CIBP (11/18/24)
11 7,380CIBP (11/17/24)
PERFORATION DETAIL
Zone Top
MD Btm MD Top TVD Btm TVD Ft Date Status
Sterling B3L ±5,818 ±5,826±5,100' ±5,107' ±8'Proposed
Sterling B3L ±5,882 ±5,886 ±5,159 ±5,162 ±4Proposed
Sterling B5 ±5,939 ±5,942±5,211' ±5,214' ±3'Proposed
Sterling B5 ±5,978 ±5,984±5,248' ±5,254' ±6'Proposed
Sterling B6 ±6,002 ±6,017±5,271' ±5,285' ±15'Proposed
Sterling A1 ±6,538 ±6,549±5,793' ±5,803' ±11'Proposed
Sterling A2 ±6,578 ±6,592±5,832' ±5,846' ±14'Proposed
Bel 5 6,667 6,6755,920' 5,927' 8'9/24/25 Isolate
Bel 6 6,726 6,7325,978' 5,984' 6'9/24/25 Isolate
Bel 7 6,745 6,7495,996' 6,000' 4'9/23/25 Isolate
Bel 7 6,752 6,7566,003' 6,007' 4'9/23/25 Isolate
Bel 7 6,7616,7676,0126,01861/19/25 Isolate
Bel 7 6,7846,7906,0356,04161/17/24 Isolated
Bel 8 6,8346,8446,0856,0951012/1/24 Isolated
BEL 8 6,854'6,864'6,105'6,115'1011/30/24 Isolated
BEL 8C 6,898'6,908'6,148'6,158'10'11/21/24 Isolated
BEL 8D 6,940'6,950'6,188'6,198'10'11/20/24 Isolated
BEL 11 7,195'7,215'6,441'6,460'20'11/19/24 Isolated
BEL 11 7,228'7,234'6,472'6,478'611/18/24 Isolated
BEL 12 7,303'7,309'6,546'6,552'6'11/18/24 Isolated
BEL 12 7,384'7,391'6,625'6,631'6'11/16/24 Isolated
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/02/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20251002
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF
T40937
BCU 13 50133205250000 203138 8/18/2025 YELLOWJACKET GPT-PERF
T40938
BCU 13 50133205250000 203138 8/26/2025 YELLOWJACKET GPT-PERF
T49038
BCU 13 50133205250000 203138 8/21/2025 YELLOWJACKET GPT-PLUG
T40938
BCU 23 50133206350000 214093 9/10/2025 YELLOWJACKET PERF
T40939
BCU 24 50133206390000 214112 9/16/2025 YELLOWJACKET PLUG-PERF
T40940
BRU 212-35T 50283200970000 198161 9/18/2025 AK E-LINE Perf
T40941
BRU 224-34T 50283202050000 225044 7/29/2025 AK E-LINE CBP/Punch
T40942
BRU 224-34T 50133207170000 225044 9/19/2025 AK E-LINE GPT/Perf
T40942
END 1-05 50029216050000 186106 9/25/2025 YELLOWJACKET IPROF
T40943
END 2-08 50029217710000 188004 8/11/2025 YELLOWJACKET PERF
T40944
END 4-50 50029219400000 189044 9/8/2025 YELLOWJACKET P-PROF
T40945
KBU 11-08Z 50133206290000 214044 9/15/2025 AK E-LINE Perf
T40946
KU 33-08 50133207180000 224008 7/1/2025 YELLOWJACKET PERF
T40947
KU 41-08 50133207170000 224005 8/28/2025 YELLOWJACKET PERF
T40948
KU 41-08 50883201990100 224005 9/16/2025 AK E-LINE Perf
T40948
MPU R-108 50029238210000 225062 8/14/2025 YELLOWJACKET SCBL
T40949
MRU K-06RD2 50733200880200 216131 9/12/2025 AK E-LINE CBL
T40950
MRU M-01 50733203880000 187046 9/20/2025 AK E-LINE Perf
T40951
MRU M-25 50733203910000 187086 9/21/2025 AK E-LINE Perf
T40952
NCIU A-21A 50883201990100 225075 8/21/2025 AK E-LINE CBL
T40953
NFU 14-25 50231200350000 210111 9/3/2025 YELLOWJACKET PERF
T40954
PBU PTM P1-08A 50029223840100 202199 9/13/2025 YELLOWJACKET SCBL
T40955
PBU W-35A 50029217990200 225076 9/17/2025 YELLOWJACKET SCBL
T40956
SRU 241-33 50133206630000 217047 9/17/2025 AK E-LINE Perf
T40957
SRU 32A-33 50133101640100 191014 9/23/2025 AK E-LINE Perf
T40958
SRU 32A-33 50133101640100 191014 9/21/2025 AK E-LINE Perf
T40958
Please include current contact information if different from above.
BCU 11A 50133205210100 224123 9/23/2025 YELLOWJACKET PERF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.10.03 09:00:56 -08'00'
DOA: Noel Nocas
Out of Office
Digitally signed by Chad
Helgeson (1517)
DN: cn=Chad Helgeson (1517)
Date: 2025.09.03 10:45:35 -
08'00'
Chad Helgeson
(1517)
By Grace Christianson at 12:22 pm, Sep 03, 2025
325-541
DSR-9/9/25A.Dewhurst 09SEP25
CT BOP test to 2500 psi. Contingency procedure.
10-404
X
BJM 9/15/25JLC 9/15/2025
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.16 07:15:35 -08'00'09/16/25
RBDM JSB 091725
_____________________________________________________________________________________
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 2/8/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240208
Well API #PTD #Log Date Log
Company Log Type
BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF
BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT
BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL
BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL
END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24
HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF
KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL
NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey
PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF
PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM
PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM
PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM
PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN
PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM
PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM
SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF
Revision Explanation: Annotations added to processed log.
Please include current contact information if different from above.
T40053
T40053
T40054
T40055
T40056
T40057
T40058
T40059
T40060
T40061
T40062
T40063
T40064
T40065
T40066
T40067
BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.07 13:25:23 -09'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address:7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): Beaver Creek Unit
GL: 160.5' BF: N/A
Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface:x- y- Zone- 4
TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD:
Total Depth:x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22.Logs Obtained:
23.
BOTTOM
3-1/2"L-80 6,728'
3-1/2"L-80 2,723'
24. Open to production or injection?Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production:Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press.24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl:Water-Bbl:
0 0790
1/27/2025 24
Flow Tubing
0
489
N/A4890
Choke Size:
2,691'
Per 20 AAC 25.283 (i)(2) attach electronic information
9.2#7,489'
Water-Bbl:
PRODUCTION TEST
1/19/2025
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation details ***
Gas-Oil Ratio:
2,691'
Tieback Assy.
6-3/4"
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
9.3#Surface 2,723'Surface Tieback
N/A
2,898' MD / 2,898' TVD
N/A
7,490' MD / 6,729' TVD
6,780' MD / 6,031' TVD
2568' FNL, 364' FWL, Sec 34, T7N, R10W, SM, AK
2558' FSL, 256' FWL, Sec 34, T7N, R10W, SM, AK
AMOUNT
PULLED
316158
316048
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
GRADE CEMENTING RECORD
2432642
SETTING DEPTH TVD
2432490
TOP HOLE SIZEBOTTOMCASINGWT. PER
FT.
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
317294 2434069
50-133-20521-01-00October 29, 2024
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
11/16/2024 224-123 / 324-638
N/A
BCU 11ANovember 3, 20241124' FNL, 1481' FWL, Sec 34, T7N, R10W, SM, AK
178.5'
Beluga Gas Pool
AKA028083
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
TUBING RECORD
L - 537 sx / T - 109 sx
CBL 11-9-24, Geotap(FTWD), LWD(PCG, ADR, ALD, CTN, PWD, DDSR), Perf/Tie In Logs.
PACKER SET (MD/TVD)
N/A
G
s d 1
0 p
d B P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
Received by J. Brooks on
2/5/2025 at 2:24pm
Completed
11/16/2024
JSB
RBDMS JSB 021325
GBJM 10/13/25 DSR-4/7/25
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval 6,761' (BEL 7) 6,012'
3220' 3219'
4635' 4292'
5540' 4853'
6523' 5778'
6638' 5891'
6712' 5964'
6746' 5998'
6817' 6068'
6975' 6223'
7053' 6301'
7129' 6372'
7299' 6541'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Beluga 12
Beluga 8
Sterling A
Sterling D
Beluga 7
Sterling C
Sterling B
Beluga 5
Beluga 6
Beluga 9
Beluga 10
Beluga 11
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.02.05 14:21:09 -
09'00'
Sean
McLaughlin
(4311)
_____________________________________________________________________________________
Updated by CJD 2-4-25
Current Schematic
Beaver Creek Unit
Well: BCU-11A
PTD: 224-123
API: 50-133-20521-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20"Conductor 133 / K-55 / -19”Surf 112’
13-3/8”Surface 68 / K-55 / BTC 12.515”Surf 2,198’
9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 2,898’
(TOW)
3-1/2”Prod Liner 9.2 / L-80 / HYD-563 2.991”2,691’7,489’
3-1/2”Tieback 9.3 / L-80 / EUE 8Rd 2.991”Surf 2,723’
OPEN HOLE / CEMENT DETAIL
20”Driven
13-3/8”TOC @ Surface 820 sx
9-5/8"TOC @ Surface 1129 sx
3-1/2”TOC @ 2704’ (CBL 11/9/24) L – 201 bbls / T - 24 bbls
JEWELRY DETAIL
No.Depth Item
1 1,346’Chemical Inj sub
2 2,691’Liner Top Packer
3 2,723’Seal Assembly
4 6,780’CIBP (1/19/24)
5 6,830’CIBP (1/15/25)
6 6,850’CIBP (11/30/24)
7 6,890’CIBP (11/29/24)
8 7,188’CIBP (11/20/24)
9 7,225’CIBP (11/18/24)
10 7,380’CIBP (11/17/24)
PERFORATION DETAIL
Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status
Bel 7 6,761’6,767’6,012’6,018’6’1/19/25 Open
Bel 7 6,784’6,790’6,035’6,041’6’1/17/24 Isolated
Bel 8 6,834’6,844’6,085’6,095’10’12/1/24 Isolated
BEL 8 6,854'6,864'6,105'6,115'10’11/30/24 Isolated
BEL 8C 6,898'6,908'6,148'6,158'10'11/21/24 Isolated
BEL 8D 6,940'6,950'6,188'6,198'10'11/20/24 Isolated
BEL 11 7,195'7,215'6,441'6,460'20'11/19/24 Isolated
BEL 11 7,228'7,234'6,472'6,478'6’11/18/24 Isolated
BEL 12 7,303'7,309'6,546'6,552'6'11/18/24 Isolated
BEL 12 7,384'7,391'6,625'6,631'6'11/16/24 Isolated
Page 1/5
Well Name: BCU-011A
Report Printed: 1/31/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:10/23/2024 End Date:
Report Number
1
Report Start Date
10/23/2024
Report End Date
10/24/2024
Operation
Cont RD and prep to move on pad, staged crane and removed windwalls, clam shell, centrifuge, inspected, held PJSM LD mast, removed poorboy skid, catwalk,
transfered BOP stack from bridge cranes to cradle.
Shipped out YJ liner job tools.
Gave BLM 72 hr notice for upcoming intital BOP test.
Removed choke house, upright water tank and cement silo, removed aux fuel tank, boiler skid, pumps, HPU skid, lube skid, three pit mods, gen skid, lowered doghouse
and removed, staged cranes and picked derrick/drill line spool off carrier, picked carrier and sub off pony walls, removed pony walls.
Removed rig matting board, picked up liner & felt. Disassembled and resealed leak on mast cylinder fitting. Worked on misc. projects and housekeeping.
Cleaned Glacier safety meeting shack and change house. Obtained measurements and sizes for bolts in crown. Gathered parts for welder to build blow-down fitting for
transfer line.
Report Number
2
Report Start Date
10/24/2024
Report End Date
10/25/2024
Operation
CCI welder arrived at 06:00. Made repair on shaker #1 cuttings drip edge, closed in gap on pushers stairs, repaired grating hinge on pit mod and fab'd and installed blow
down hardwarer for transfer line. Steam on Wheels rep shot grade for rig footprint on BCU-11 and brought in dozer. Rig crew installed tree and SSV on BCU-09A with
lead operator and Wellhead Rep.
Sent AOGCC 72 hr notice for initial BOP test, up dated BLM for same.
Steam on Wheels dozer spread weed free gravel and shot final grade for rig footprint on BCU-11.
Crew measured and marked lay out, put down felt, liner and rig mats. Set pony walls and pinned cross beams. Set IR HPU in between pony subs.
Worked on EAM's. Set iron roughneck heater between pony subs. Removed kill & vibrator hose off the top of pony subs. Measured high pressure hoses between pits &
pumps, pump to pump, and pump to sub, to order critical spares.
Crew change, held PTSM. Cont. working on misc. projects. Sweep snow off rig mats prior to spotting & setting rig. Cont. working EAM's. Installed new LED light in the
mast.
Report Number
3
Report Start Date
10/25/2024
Report End Date
10/26/2024
Operation
CCI on location at 06:00 and warming up equipment while holding PJSM with rig crew. Spotted cranes and sub, set sub on pony walls and centered up over well, set pit 1,
jig, doghouse and raised, set choke house, pump 1 skid, raised V door windwalls, transfered BOP stack to cellar bridgecranes, set pit 2, inspected and stood mast, set
pump 2, set centrifuge, set pit 3 and lube skid, set poorboy skid.
Set HPU skid, clam shell, put down liner for catwalk, hung windwalls on pits, set gen skid, strung electric cords, start install inter-connects throughout rig, set boiler skid
and catwalk, folded over beaver slide, put down liner and set gen 3, upright water tank and cement silo, set service shacks, fired gen and powered rig, installed vent line
on degasser vessel, HandyBerm installed berm around rig, stood degasser vessel.
Installed subbase tarps, Got steam circulating through the rig, along with water & air. Installed steam traps. Plugged in powered up service shacks. Off loaded WSI tools.
Spooled drill line on DWKS drum, secured drill line on dead man. Un-hung blocks, installed turn buckles on top section of derrick to TQ tube. Pinned bottom section of TQ
tube to top section, Scoped derrick and plugged in crown/derrick lights. Cont. R/U in the pit system.
Crew change, held PTSM. Cont. with R/U. M/U "T" bar to mast/TQ tube. Performed mast inspection and connected Pason encoder at the crown. Held PJSM, R/U
hoisting gear, hoisted TDS from catwalk to rig floor. M/U TQ bushing to TQ tube, pinned TDS to TQ bushing. R/U Kelley hose and service loop to TDS. Installed shaker
slides and R/U dump line from possium belly. Changed out suction valve rubber in pit #5. R/U centrifuge, changed out camlock on pit #3. Laid & attached felt apron, by
mud mixing area outside of rig berm. Bi-passed auto-fill valve on boiler water inlet, because hotwell was overflowing and back filling the blow down tank. Repaired steam
hose on heater in mud mod #1, Checked pre-charge pressure in koomey bottles, Cont. working on R/U Pason cables around the rig. Re-connected & charged battery on
Gen #1.
Report Number
4
Report Start Date
10/26/2024
Report End Date
10/27/2024
Operation
Took on rig fuel, RU comm's to service shacks and doghouse, dressed rig floor and topdrive, strung Pason cords for pit PVT's, installed gas alarm lights and sensors, rig
electrician tested same, function test various equipment for rig acceptance checklist, C/O CMV #2, RU geronimo line and anchor.
Transfer water throughout pits and plumbing, had bad king nipple on transfer line, removed line for C/O, removed shipping beam in cellar, removed dry hole cap on
wellhead and installed BOP stack, hung flow box under rotary, NU choke and kill lines, called out welder and shortened flow riser, C/O oil pan gasket on #1 gen.
Greased choke mainifold, manual choke & kill, and HCR's on stack. M/U 4.5" test JT & FOSV. Function tested BOP components (ok). Loaded catwalk pipe racks with 4.5"
DP.
Flooded surface lines w/ H2O. Tested surface lines T/2300 psi (ok). Run in test plug/test JT. Flooded stack, choke mainfold , and mud lines, purged out air. Started
performing shell test- 250 Low/ 2500 High For 10/5 mins.
Crew change, held PTSM. Finished performing shell test. Tested against replaced CM valve #2 (ok). Tested electric choke to make sure it was clocked correctly and will
catch pressure (ok). R/U testing equip. and pulled test JT/plug. Blew down CM and mud lines. Brought into pit system, used 6% KCL PHPA mud from tank farm.
Changed out grabber box dies, strapped & tallied 22 jts of 4.5" DP, cleaned & cleared rig floor. Cleaned up CM valve to be rebuilt.
Servied rig- Greased & inspected crown, blocks, wash pipe, TDS, IR, DWKS, brake linkage, drive shaft, chain case, and saver-sub. Checked oil in floor motor.
Started building new batch of 6% KCL PHPA mud in premix tank. Dressed out shaker with API 140's. Serviced centrifuge. Obtained stack measurements. Changed oil in
TDS. Cleaned & detailed choke house. Cleaned & orgainized buildings and modules on and off rig.
Report Number
5
Report Start Date
10/27/2024
Report End Date
10/28/2024
Field: Beaver Creek
Sundry #:
State: ALASKA
Rig/Service: HEC 169Permit to Drill (PTD) #:224-123
Wellbore API/UWI:50-133-20521-01-00
Page 2/5
Well Name: BCU-011A
Report Printed: 1/31/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Rig electrician wired in spare camp gen to transformer switch for back up power source to office trailers, finished building 6% KCL mud in pits (also had 360 bbls saved
from last well), rig mechanic checked all agitators gear box oil, performed EAM's on various equipment while waiting on BLM Rep to arrive (driving from Anchorage). set
test plug with test joint, flooded surface equipment, purged air and shell tested to 2500 psi. BLM Rep on location at 11:50.
Accepted rig at 12:00 noon.
Rig electrician tested gas alarms/lights, functioned flow show and PVT alarms, tested all BOPE at 250 low for 5 min, 2500 high for 10 min with BLM Rep witness (AOGCC
waived at 08:31). Tested with both 3 1/2" and 4 1/2" test joints (no single gate on stack). Performed drawdown test. Had 1 F/P on upper ram test w/3 1/2" test jnt (gland
nut leak).
Sent upcoming spud notification (milling of window) and FIT to BLM.
Blew down & R/D testing equip. - CM & mud lines. Puled test plug, set 9" wear ring, RILD's x 2. De-energized & bled down accumulator, removed the annular isolation
valve from the open side and installed it on the closed side, re-energized the accumulator. Set up pipe racks, loaded, strapped, and tallied = 80 jts of 4.5" DP. Greased
CM and prepped to P/U pipe.
M/U diffuser to first jt of 4.5" DP. Cont. picked up and singling in the hole F/surface-T/2530'. POOH racking back stands F/2530'-T/1688'.
Crew change, held PTSM and weekly safety meeting with rig crew. Resumed POOH F/1688'-T/ surface. Re-loaded pipe racks, strapped & tallied pipe. Singled in the hole
F/surface-T/2516'. POOH racking back pipe in the derrick.
Report Number
6
Report Start Date
10/28/2024
Report End Date
10/29/2024
Operation
Cont POOH rack back DP in derrick from 2516' to surface. PU singled in hole an additional 56 jnts DP, POOH racked back for a total 108 stands.
Serviced rig and topdrive while staging WIS tools for PU.
PU single HWDP jnt, MU XO, watermelon mill, float sub with float, 9 5/8" scraper and tapered mill. PU singled in hole 16 more jnts HWDP to 540'.
Cont TIH from 540' to 2926', MU topdrive, up wt 70K, dwn wt 70K. Eased down and tagged TOC at 2940'. Reciprocated string as per WIS Rep to clean up whipstock set
area at 2900'.
Primed both mud pumps, pumped 20 bbl hi-vis spacer followed with 9.0 ppg 6% KCL mud and displaced well, over boarded produced water for disposal. Pumped at 271
gpm-120 psi up to 181 psi. Shut down and obtained SPR's with mud in hole.
POOH from 2930' racked back DP and 8 stands HWDP. LD 8.5" starter mill/scraper assy. P/U-70K S/O-73K
Cleaned & cleared rig floor. Staged Tri milling assy. and whipstock on catwalk. Held PJSM on M/U BHA #2.
P/U 5" flex jt. M/U running tool & Tri mills to bottom of flex jt. M/U UBHO sub, float sub, and MCBPV to top of flex jt. Orientated/scribed starter mill/whipstock anchor point
to UBHP sub indicator. Set back milling assy. P/U WIS Track Master HYD expandable anchor whipstock and set in false rotary table. Installed 55K shear bolt in top of WS
slide. P/U & M/U starter mill to WS by shear bolt. Connected HYD line from WS to started mill port. Eased in the hole to top of running tool. Broke connection and filled
HYD system with 6 gals of HYD oil, torqed connection.
M/U XO. Eased in the hole at 50' per min w/ WS/8.5" milling assy. on 4.5" HWDP/DP- BHA #2 F/89.66'-T/2898' P/U-71K S/O-73K
R/U YJ E-line unit & Gyro tool.
RIH w/ Gyro data tool to UBHO set depth of 2811'. Started taking check shot & orientating Gyro TF, Final TF of 216°. POOH with Gyro tool.
Report Number
7
Report Start Date
10/29/2024
Report End Date
10/30/2024
Operation
R/D Eline, M/U 1 stand of DP kelly up to top drive and set whipstock on depth, set anchor, worked string and sheared bolt 123k on hook load, top of ramp 2898' bottom of
ramp 2912' set @ 216° az.
Milled window f/ 2898' t/ 2912' w/ 414 gpm 1766 psi and 90 rpm 4.5 to 8.8 torque 1-3 fph 1-4 WOB Drilled 20' of new hole f/ 2912' to 2932', work through window x 5
without issues turn off rotarty and slide through window clean 2-3k drag seen at mill
Circulate 20 bbl hi vis sweep around, sweep came back on time with a 10% increase in cuttings. Obtained SPR's. Pulled inside casing. Flow checked well for 10 min-
static.
R/U testing equip. flooded lines & purged out air. Performed FIT to EMW of 13.1 ppg 634 psi. Pumped in 32.2 gals bled back 24.2 gals. R/D & blew down testing equip.
POOH F/2932'-T/BHA #2. Racked back HWDP, L/D WIS milling BHA #2, with upper 8.5" mill being in gauge.
P/U and Johnny Whacked stack to flush out any remaning metal shavings in ram cavities, flow box, and mannul valves on the stack.
Rig service- Inspected & greased crown, blocks, wash pipe, TDS, IR, DWKS, brake linkage, drive shaft, and saver sub. Performed derrick inspection and adjusted
magnets on TDS.
Cleaned & cleared rig floor, stagged directional BHA #3 on the catwalk.
P/U 6.75" rat hole BHA #3 with Tri-cone bit. Scribed motor & MWD tool too UBHO sub. P/U remaining MWD tools, shallow pulse tested (ok). Run in jar stand and HWDP.
Cont. RIH with BHA #3 at report time.
Report Number
8
Report Start Date
10/30/2024
Report End Date
10/31/2024
Operation
Change Saver sub
RIH f/ 1924' t/ 2923' no issues going through window
R/U ELine RIH and attempt to get gyro tool face, unable to get consistent tool faces, POOH and inspect tool string install tattle tail, RIH and set down three different tool
faces, POOH tattle tail looked like it set down, RIH w/ new tattle tail, set down three different tool faces, POOH tattle tail looked like it set down in profile.
POOH f/ 2923' t/ UBHO sub inspect UBHO, everything good, dry run tool string, Wrong indexer unable to get into profile.
Change UBHO size and placement, scribe high side to UBHO, RIH T/2992', slid through window with no issues.
R/U YJ E-line & Gyro data tools. RIH to UBHO sub, orientated TF- 238°. POOH and tied back Gyro tools.
Slide/rotary drilled for separation F/2932'-T/3244', orientating TF w/ Gyro on E-line every 60', while attempting to get surveys with MWD. At 3181' started seeing high side
TF with MWD tools. Inc.= 6.28° Estimated distance from original well bore- 15'. P/U-77K S/O-77K ROT-77K GPM-257 SPP-1298 psi RPM-40 TQ-3.5K WOB-10K MW-9.0
ppg Max gas 29 unit.
Pumped 20 bbl Hi-Vis sweep around while R/D YJ E-line and Gyro data tools. Sweep came back on time with a 30% increase in cuttings. Flow check.
Field: Beaver Creek
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Milled window f/ 2898' t/ 2912
Performed FIT to EMW of 13.1 ppg 634 psi.
Page 3/5
Well Name: BCU-011A
Report Printed: 1/31/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Report Number
9
Report Start Date
10/31/2024
Report End Date
11/1/2024
Operation
POOHJ w/ BHA #3 f 3244' t/ 676' with no issues
Rack back and L/D BHA #3 Bit graded 1-1 in gauge.
Service rig and draw works, grease top drive and blocks, clean suction screens, grease crown, inspect brakes and linkage
M/U BHA #4 as per DD/MWD triple combo BHA, upload MWD shallow test, load sources RIH w/ BHA f/ derrick t/ 680'
RIH f/ 680' t/ 3244' P/U-76K S/O-75K
Drilled ahead F/3244'-T/3500', pumped sweep at 3486', sweep came back on time with a 50% increase in cuttings. Obtained new SPR's. Madd passes as per MWD.
Racked back 1 std. T/3435'. P/U-78K S/O-76K ROT-77K GPM-240 SPP-1084 psi RPM-50 TQ-3.8K WOB-1K MW-9.0 ppg ECD-9.34 ppg Max gas- 21 units.
R/U YJ E-line & Gyro tool, RIH w/ Gyro tool T/3518' WLM (UBHO sub). Pulled up hole T/3300', obtained Gyro tie in surveys F/3300'-T/3000', every 100' as per MWD. R/D
& released YJ E-line & Gyro data.
RIH 1 std. out of the derrick. Resumed directioonal drilling 6.75" production hole F/3500' to current depth of 3878'. Building 4 degrees per 100' as per wp03. Obtained
SPR's @ 3766' P/U-83K S/O-80K ROT-81K GPM-244 SPP-1130 psi RPM-50 TQ-3.9K WOB-2.3K MW-9.0 ppg ECD-9.35 ppg Max gas- 27 units. Distance to well plan:
38.66' 28.82' Low 26.84' Right.
Rotating & reciprocating pipe while pumping 20 bbl Hi-Vis sweep around.
Report Number
10
Report Start Date
11/1/2024
Report End Date
11/2/2024
Operation
Drill 6 3/4'' Hole Section f/ 3878' t/ 4256' 250 gpm 1255 psi 50 rpm 4.7k tq on bottom, Max Gas 35 units, 9.0 ppg MW ECD 9.51ppg, 3k WOB, 89k PUW 85k SOW 87k
ROT
Circulate bottoms up, Obtain survey and SPR's, Flow Check well stataic, blow down lines
POOH f/ 4256' t/ 3250' No issues
Service rig and top drive, grease top drive and crown, inspect draw works and brake linkage and drive shaft.
RIH f/ 3250' t/ 4255' wash last stand to bottom, Pump Hi Vis Sweep around.
Drill 6 3/4'' Hole section f/ 4256' t/ 4505' 250 gpm 1290 psi 50 rpm 4.7k torque on bottom, 5k WOB, Max gas 4 units, 9 ppg MW 9.59 ppg ECD, 94k PUW 87k SOW 86k
ROT
Directioonal drilling 6.75" production hole F/4505'-T/4945'. Finished our 4 degree build per 100' at 4850'. Pumped tandem sweep at 4756', sweep came back on time with
a 20% increase in cuttings. Obtained SPR's @ 4756' P/U-97K S/O-87K ROT-86K GPM-250 SPP-1327 psi RPM-50 TQ-5.2K WOB-3K MW-9.05 ppg ECD-9.73 ppg Max
gas- 11 units.
Directioonal drilling 6.75" production hole F/4945' to current depth of 5318'. Started our 3.5 degrees per 100' @ 5100' as per wp03. Pumped tandem sweeps @ 5227,
back on time with a 80% increase in cuttings, obtained new SPR's. P/U-100K S/O-85K ROT-92K GPM-246 SPP-1252 psi RPM-50 TQ-5.4K WOB-3.5K MW-9.2 ppg
ECD-9.8 ppg Max gas- 17 units. Distance to well plan: 3.76' 1.11' High 3.59' Left.
Report Number
11
Report Start Date
11/2/2024
Report End Date
11/3/2024
Operation
Drill 6 3/4'' Hole Section f/ 5318' t/ 5758' 250 gpm 1450 psi 50 rpm 5.9k tq on bottom, 3k WOB MW 9.2 ppg 9.81 ppg ECD, 107k PUW 88k SOW 97k ROT
Circulate botttoms up, obtain survey and SPR's, Flow check well static
POOH f/ 5758' t/ 3250' without issues
Pump Hi Vis Sweep around, back on time 15% increase in cuttings
POOH f/ 3250' t/ 2876' no issues passing through window
Service rig and top drive, inspect brake linkage and drive shaft, grease blocks and crown.
RIH f/ 2876' t/ 5756' wash and ream last stand to bottom, worked through tight spot-on elevators @ 4658'. Pumped tandem sweep around, back on time w/ a 40%
increase in cuttings.
Cont. directional drilling 6.75" production hole F/5756'-T/6011'. Sliding for drop at 3.5° per 100'. P/U-124K S/O-94K ROT-106K GPM-250 SPP-1365 psi Flow- 20%
RPM-50 TQ-6.3K WOB-3.5K Diff-168 psi MW-9.15 ppg ECD-9.82 ppg Max gas- 190 units.
Crew change, held PTSM. Cont directional drilling 6.75" production hole F/6011' to current depth of 6458'. Pumped tandem sweeps @ 6283' back on time with a 50%
increase in cuttings, obtained new SPR's. P/U-150K S/O-96K ROT-110K GPM-242 SPP-1386 psi RPM-50 TQ-8.8K WOB-3K MW-9.15 ppg ECD-9.79 ppg Max gas- 187
units. Distance to well plan: .64' .51' High .39' Left.
Report Number
12
Report Start Date
11/3/2024
Report End Date
11/4/2024
Operation
Continue Drilling 6 3/4'' Hole section f/ 6458' t/ 6845' 250 gpm 1575 psi 50 rpm 9.4k tq on bottom 3k WOB, max gas 195 units MW 9.15 ppg ECD 9.85 ppg, 155k PUW
100k SOW 116k ROT
Drill 6 3/4'' Hole Section f/ 6845' t/ 7144' 250 gpm 1516 psi 50 RPM 10.8 tq on bottom 293 units max gas 9.15 ppg MW 9.82 ppg ECD 7k WOB 160k PUW 102k SOW
120k ROT
Cont. directional drilling 6.75" production hole F/7144' to TD of 7490' called by Geologist. P/U-200K S/O-105K ROT-126K GPM-250 SPP-1814 psi Flow- 20% RPM-50
TQ-10.8K WOB-6K Diff-356 psi MW-9.15 ppg ECD-9.94 ppg Max gas- 96 units. Distance to well plan: 13.65' 13.44' High 2.36' Left
Circulated STS, shot on bottom survey, obtained new SPR's, flow checked well- slight seepage. GPM-242 SPP-1296 psi RPM-50 TQ-10K MW-9.15 ppg ECD-9.8 ppg
Max gas 8 units.
Pulled wiper trip F/7490'-T/5729' with 15-20K drag, worked through multiple tight spots on elevators. P/U-190K S/O-105K. Calculated hole fill- 9.66 bbls Act- 15.44 bbls
Diff- 5.78 bbl over
Monitored hole on TT while servicing rig. Inspected & greased crown, blocks, TD, wash pipe, IR, DWKS, brake linkage, drive shaft, and cleaned MP suction screens.
Static loss rate= 1.6 bph.
RIH F/5788'-T/7426', with no issues. Filled pipe, broke circulation, washed last std. down. P/U-130 S/O-93K. Calculated pipe Disp- 30.5 bbls Act- 28.78 bbls Diff-1.72 bbls
Field: Beaver Creek
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 4/5
Well Name: BCU-011A
Report Printed: 1/31/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Pumped tandem sweep around at report time. P/U-170K S/O-107K ROT-126K GPM-268 SPP-1557 psi RPM-70 TQ-11.5K MW-9.15 ppg ECD-9.92 ppg Max gas- 950
units.
Report Number
13
Report Start Date
11/4/2024
Report End Date
11/5/2024
Operation
Finished pumping tandem sweep around back on time 50% increase in cuttings, flow check well static, blow down lines
POOH on elevators f/ 7490' t/ 680' no issues, dropped drift @ 7079'
Rack Back BHA, Unload sources, upload MWD, L/D remainder of BHA bit graded 1-1 in gauge
Clean and clear rig floor, R/U Parker TRS, PJSM
Run 3.5'' 9.2# L-80 563 wedge liner as per detail, M/U float equipment and check floats, good, Continue RIH w/ 3.5'' Liner as per detail F/66.43'-T/2867', obtained weights
before exiting 9-5/8" window. P/U-35K S/O-35K. Cont. P/U and running 3.5" liner F/2867'-T/3188'.
Had HYD hose on Parkers power tongs spring a leak, changed out with same.
Resumed running 3.5" liner as per run tally F/3188'-T/3730'. P/U-42K S/O-40K
Crew change, held PTSM. Cont. running 3.5" liner as per run tally F/3730'-T/4760'. P/U & M/U Baker SLZXP(HRD-E) hanger/packer as per Baker rep. RIH on 1 std of
HWDP T/4872'.
CBU, staged up MP. R/D Parker casing equip while circulating. GPM-255 SPP-509 psi Flow-20% MW-9.15 ppg. Max gas- 11 units. Pumps off P/U-52K S/O-50K
Resumed RIH with 3.5" liner on DP.
Report Number
14
Report Start Date
11/5/2024
Report End Date
11/6/2024
Operation
Continue RIH w/ 3.5'' Liner on 4.5'' DP f/ 7120' t/ 7490' wash down and tag on last stand, Space out L/D jt of Dp and P/U DP pups
Circulate and condition mud f/ cement Job stage rate to 5 bpm 650 psi Max Gas at bottoms up 291 units, R/U cementers and cement head, PJSM with hands
Circulate water through lines, Shut down and PT lines t/ 4620 psi, Pump 30 bbls of 11 ppg spacer, pump 201 bbls of 12.5 ppg lead 24 bbls 15.3 ppg tail, open lines and
wash up across plug to cuttings tank, drop plug and displace with 73.5 bbls of 9.2 ppg mud, pressure up 500 psi over final circ ulation pressure to 1600 psi, hold pressure
for 3 min pressure up t/ 2700 psi seen jump in drill pipe slack off and verify hanger set, set down 40k, pressure up t/ 4000 psi to set packer and nuetralize pusher tool,
check floats 3/4 bbl bled back, L/D Cement head and lines, M/U top drive and set down 44k x3 with rotarty to attempt to shear dog sub, R/U to circulate out cement, CBU
6 bpm 196 psi 30 bbls of spacer 37 bbls of cement returned to surface, lost 25 bbls through out job, CIP 12:30 pm
POOH f/ 2723' t/ surface L/D running tools dog sub sheared
Clear floor M/U stack washer and flush stack with black water
M/U polish mill RIH F/37' tag at 2724'. Screw in and obtain parameters, 111GPM=106PSI, 10RPM=2.5k TQ. P/U-55K, S/O-57K, ROT-55K. Polish SBR as per Baker rep.
Displace well over to CI water circulated a total of 188bbls. 244GPM=246PSI. Perform 30min flow check-good.
POOH f/2724' t/582' L/D 58 jnts of drill pipe. Vacuuming wiper balls and doping connections.
Cont to POOH f/582' to surface' L/D 26 jnts of drill pipe. Vacuuming wiper balls and doping connections. L/D polish mill assembly.
M/U johnny whacker and RIH out of derrick with 8 stands of HWDP and 33 stands of 4.5" DP f/ surface t/2431'.
Screw into stump and pump CI water through drill string. Blow down surface lines.
POOH L/D DP singles f/2431' t/497'. Vacuuming wiper balls and doping connections. Rack Back 8 stands of HWDP t/ Surface
Report Number
15
Report Start Date
11/6/2024
Report End Date
11/7/2024
Operation
R/U test equipment purge lines test liner lap and liner t/ 2500 psi f/ 10 min on chart good test, 2.3 bbls pumped in 2.3 bbls bled back, R/D test equipment, blow down lines
RIH w/ 8 stands of HWDP and 34 stands of DP t/ 2630'
Circulate through pipe to clean string
POOH L/D Dp and HWDP f/ 2630 t/ surface
Service rig and top drive
Pull Wear ring, R/U Parker TRS
RIH w/ 3.5'' EUE 8rnd Tieback string as per detail f/ surface t/ 1366'
M/U Chemical injection mandrel, hang sheave in derrick and R/U control line spooler, terminate control line to chemical injection mandrel and pressure test line t/ 3000 psi
good
Continue RIH w/ 3.5'' Tieback as per detail f/ 1366' t/ 2698' banding control lie to each joint.. P/U extra jnt and land out at 2724'. L/D extra jnt and M/U space out pup g
under jnt 89. P/U landing jnt/hanger. Terminate control line and tested to 3000psi for 5 min. Land hanger, P/U-34k, S/O-35k, saw seals enter SBR. No-go 1.18' off seat.
R/U test equipment, flood stand and choke manifold. Pumped 0.57bbl down tubing to achieve 2590psi for 30min-good test bled back 0.57bbl. R/U on 9-5/8" IA Pressured
up to 2550psi, gland nut was leaking on lock down. Bled off and tightened gland nut. Pumped 1.78bbl to achieve 2550psi for for 30min-good test. Bled back 1.78 bbl. R/D
test eqipment and install 2 way check.
Flush top drive, choke manifold, gas buster, kill/choke lines, mud pumps,charge pumps and pit lines with baraklean, followed wi th baracorr.
Removed 4 way chains. Opened ram doors, cleaned, inspected, and grease cavities. Remove flow line, flow riser, and drip pan.
Report Number
16
Report Start Date
11/7/2024
Report End Date
11/8/2024
Operation
Nipple down stack and attatch to bridge cranes and skid out of way, install tree on wellhead and toque down, test neck seals void and tree to 5000 psi f/ 10 min good
tests, secure well
Finish cleaning pits, clear floor of handling equipment and subs, L/D tongs bails and elvators, Rig down high pressure mud line s around rig.
R/D top drive and install in craddle, remove torque bushing and prep to scope derrick, continue rigging down rig modules, remove third party shacks from around rig.
Crane out rig floor wind walls crane out gen 3 and gas buster, crane out centrifuge
Field: Beaver Creek
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 5/5
Well Name: BCU-011A
Report Printed: 1/31/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Disconnected electrical lines from mud pits. Removed T-Bar from derrick. R/D Iron roughneck. Removed BOP stack from sub with crane, installed single gate and
secured in cradle. Removed Gas buster with crane. Drained 2" hydraulic line in derrick. Install shipping beams and secured bridge cranes. Removed brake handle, drive
line and brake linkage. Unspooled drill line from drawworks. Scopped derrick down and secured drill line and hydraulic lines in derrick. Blow water and steam lines down.
Lai derrick over, disconnected derrick cylinders and disconnected hydraulic lines and tied up wire rope.
Disconnect electrical, hydraulic, air, water, fuel and Pason lines through out rig. Lower catwalk slide and R/D. Finish R/D mud pits.
Report Number
17
Report Start Date
1/2/2025
Report End Date
1/3/2025
Operation
6:00 Arrive at PWL, Travle to Beaver Creek
7:00 Arrive at Beaver Creek, Safety meeting
7:30 Move Equipment to BCU-11 and begin rig up
9:30 Pressure test, o-ring fail, pop off and replace
10:00 Pressure test to 2500
10:30 Pressure well up to 1200 Rih w/2.5 Lib to 6632' kb, return with .5'' circular impression
11:45 Rih w/ 2.5X6' DD Bailer turn around and look for fluid level. Fluid near surface
13:15 Rih w/ 1.75 Lib on 3' 1 3/4 stem, Clean impression of top of CIBP
14:00 Begin Rig down
16:00 Leave Beaver Creek
17:00 Arrive at PWL
Field: Beaver Creek
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 1/2
Well Name: BCU-011A
Report Printed: 2/4/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:10/31/2024 End Date:
Report Number
1
Report Start Date
11/9/2024
Report End Date
11/10/2024
Last 24hr Summary
PTW/PJSM. Logged CBL from tag @ 7424'-2450'. TOC @ 2704'
Report Number
2
Report Start Date
11/10/2024
Report End Date
11/11/2024
Last 24hr Summary
PTW/PJSM, MIRU Fox Coil. PT 250/3000
Report Number
3
Report Start Date
11/11/2024
Report End Date
11/12/2024
Last 24hr Summary
PTW/PJSM,PT 250/3000, Tag @ 7431' PUH to 7421', circ out drilling mud from tbg to fresh water. Reverse well dry W/121.8K scf N2.
Report Number
4
Report Start Date
11/16/2024
Report End Date
11/17/2024
Last 24hr Summary
Ops crew, plow snow, move and set up flow back tank with spill containment. PTW/PJSM with YJ E-line, move equipment from BC-9A to BC-11A and RU. T/I/O -
2000/75/0. PT 250 psi / 3000 psi. SITP - 1979 psi. RIH with 6'gun and perforate the BEL_12 sand 7385'-7391'. Secure well, rig back e-line and flow test. Bled well in 200
psi increments with 15 minute pressure builds down to 80 psi, no LEL detected. SDFN
Report Number
5
Report Start Date
11/17/2024
Report End Date
11/18/2024
Last 24hr Summary
PTW/PJSM with YJ E-line and Fox N2. RIH with GPT and locate fluid level at 1130'. RU Fox N2 and PT hard lines 250 psi/4500 psi. Go online with N2 at 1200 scfm and
shut down at 4000 psi. RIH with GPT and locate FL at 6575'. Continue with N2 and confirm fluid is depressed to perfs at 7385'-7391'. RIH and set CIBP at 7380'. Trap
2500 psi on well. Secure well and SDFN.
Report Number
6
Report Start Date
11/18/2024
Report End Date
11/19/2024
Last 24hr Summary
PTW/PJSM. Rig YJ E-line back on well. T/I/O - 2500/20/0. Bled well down to 2000 psi. RIH and perforate the BEL_12 (7303'-7309'). Drop down below perfs, draw well
down to1900 psi, monitor build and check for fluid level. OOH, gun wet. RIH with GPT and locate fluid level at 7335' (45' above CIBP at 7380'), fluid slowly moving uphole.
RIH and perforate the BEL_11 (7228'-7234'), gun wet and pressure slowly rising. M/U CIBP and set at 7225'. SITP-1914 psi. Secure well and SDFN.
Report Number
7
Report Start Date
11/19/2024
Report End Date
11/20/2024
Last 24hr Summary
PTW/PJSM with YJ E-line. T/I/O -1893/20/0. E-line crane shut down pre-rig up, wait on replacement. On arrival, RU and RIH with 20' perf gun and perforate the BEL_11
(7195'-7215'). Follow with GPT and locate fluid level at 7000'. Secure well and SDFN.
Report Number
8
Report Start Date
11/20/2024
Report End Date
11/21/2024
Last 24hr Summary
PTW / PJSM with YJ E-line and Fox N2. T/I/O: 1909/20/0. R/U E-line and GPT. M/U N2 iron and PT 250/4000 psi. Go online with N2 to 3500 psi. RIH w/ GPT and locate
fluid level at 7215'(BEL_11 7195'-7215'). Set CIBP at 7188'. Draw down well to 2000 psi and perforate the BEL_8D sand 6940'-6950'. Minimal pressure increase, gun sub
wet. Secure well, SDFN and monitor overnight pressure.
Report Number
9
Report Start Date
11/21/2024
Report End Date
11/22/2024
Last 24hr Summary
PTW/PJSM with YJ E-Line. Rig back on well, RIH with GPT and locate fluid level at 7030' (158' above CIBP & 80' below perfs at 6940'-6950'). RIH and perforate the
BEL_8C sand 6898'-6908'. Minimal pressure increase, gun dry. RIH with CIBP to set between BEL_8D & 8C. Plug won't pass upper perfs, POOH and plug showed
damage at metal seal between slips and element. RIH with GPT and junk basket with 2.75" gauge ring. Draw down well in 200 psi increments with 15 minute pressure
builds. Fluid level detected at 6600'. Continue in hole throuh perfs with no issues. After third bleed (1200 psi), fluid level at 6250'. Pull out with e-line and rig back. Continue
flow back to 500 psi, SI 30 minutes with no build in pressure. Secure well and SDFN.
Report Number
10
Report Start Date
11/24/2024
Report End Date
11/25/2024
Last 24hr Summary
PTW/PJSM with Fox N2. T/I/O: 575/20/0. MIRU and PT 250 low/4000 high. Pump N2 at 1100 scfm and well broke over depressing fluid at 2200 psi (55K scfs). Continue
pumping to 3500 psi (Total-76.8k scfs). Secure well, RD and move N2 equipment to BC-9A.
Report Number
11
Report Start Date
11/29/2024
Report End Date
11/29/2024
Last 24hr Summary
PTW/PJSM. SITP 2055psi. RU YJ E-line. PT lubricator to 250/3000 psi - good test. RIH w/ GPT and find fluid level @ 6,695'- POOH. RU Fox N2. Pump N2 at 1200
scfm and pressure up to 3500 psi. Pumped 37,059 scf (398 gals) N2. RIH w/ GPT to 6,920'- did not see fluid level, POOH. RIH w/ CIBP and set @ 6,890'. Confirm set
w/ tag, POOH. SDFN.
Report Number
12
Report Start Date
11/30/2024
Report End Date
11/30/2024
Last 24hr Summary
PTW/PJSM. SITP 2070 psi. RU YJ E-line. RIH w/ 10' x 2 3/8" 5SPF 60DEG guns and perf Bel 8 sand (6,854'-6,864'). RIH w/ GPT and find fluid @ 6,410'. RU Fox N2,
pump N2 and saw pressure breakover @ 3000 psi. Pumped 45,747 scf (491 gals) N2. Confirm fluid is at bottom perf (6,864') w/ GPT. RIH w/ CIBP and set @ 6,850'.
POOH and SDFN.
Field: Beaver Creek
Sundry #: 324-638
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:224-123Permit to Drill (PTD) #:224-123
Wellbore API/UWI:50-133-20521-01-00
,
perforate the BEL_12 sand 7385'-7391
Page 2/2
Well Name: BCU-011A
Report Printed: 2/4/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
13
Report Start Date
12/1/2024
Report End Date
12/1/2024
Last 24hr Summary
PTW/PJSM. SITP 1990 psi. RU YJ E-line. RIH w/ 10' x 2 3/8" 5SPF 60DEG guns, tag CIBP @ 6,850', and perf Bel 8 sand (6,834'-6,844'). RIH w/ GPT and tag CIBP @
6,850'- no fluid. PU to 6,700' and bleed well to 1555 psi and saw pressure influx, tools blown up hole. RIH w/ GPT and tagged @ 6,632' (~200' above perfs)- no fluid.
POOH, RDMO YJ E-line.
Report Number
14
Report Start Date
1/2/2025
Report End Date
1/3/2025
Last 24hr Summary
PTW/PJSM, PT 250/2500, Ran 2.50" LIB tagged @ 6434' KB (impression of shear stud from CIBP), Ran 1.75" LIB tagged @ 6634' KB (impression of shear stud and
inner mandrel of CIBP)
Report Number
15
Report Start Date
1/13/2025
Report End Date
1/14/2025
Last 24hr Summary
PTW, PJSM with crew. Move Fox CTU #10 from BCU-18RD to BCU-11A, Spot tanks and equipment. Perform BOP test 250/3500psi. AOGCC Witness Waived by Jim
Regg on 1/12/25. Secure location for the night.
Report Number
16
Report Start Date
1/14/2025
Report End Date
1/15/2025
Last 24hr Summary
PTW, PJSM with Fox Crew, Stack up lubricator, Make up YJOFS 2.81" revers clutch milling BHA. Stab on well, PT lube/iron to 250/3500psi. RIH and tag CIBP at
~4,500'. Mill and push plug down to 6,870'. POOH while maintaining 800psi on TBG. FP tree with meth. Blow down reel with N2 for FP. Lay down CTU for the night.
Report Number
17
Report Start Date
1/15/2025
Report End Date
1/16/2025
Last 24hr Summary
PTW/PJSM with crew. MIRU Yellow jacket E-line. PT lubricator 250 psi low/3000 psi high Make up junk basket drift clean to tag at 6,861' ELMD. POOH and make up
3.5" CIBP. RIH and perform correlation pass. Confirm tie in with geo and set CIBP at 6,830'. POOH and lay E-line unit down for the night.
Report Number
18
Report Start Date
1/16/2025
Report End Date
1/17/2025
Last 24hr Summary
PTW/PJSM with crew. Rig up CT injector and lubricator. Make up 2.12" nozzle BHA with 2 stingers. RIH to 6,813' and blow well dry with 144,000 SCF of N2. POOH and
pressure up well to 2,000psi of gas for perf job. RDMO CTU and send to KGF.
Report Number
19
Report Start Date
1/17/2025
Report End Date
1/18/2025
Last 24hr Summary
PTW/PJSM with crew, MIRU Yellow Jacket E-line. Make up 6'x2" 6spf 60 degree phasin perf gun. RIH and correlate from 6,826-6,550'. Confirm tie in with GEO. RIH
and perforate Bel 7B 6784-6790'. POOH and lay down perf gun, small amount of water found in bull plug. Make up GPT and found fluid level at 6,537'. Monitior fluid
level for 40 minutes and found it static. Start Bleeding WHP from 2,032psi - 700psi. Fluid level rose to 6,400'. Discussed with OE and decided to RD for the night.
Report Number
20
Report Start Date
1/18/2025
Report End Date
1/19/2025
Last 24hr Summary
PTW/PJSM with crew. MIRU E-line, make up GPT tools. RIH and found fluid level at 5,385’. POOH and rig up Fox N2 unit. Pressure up well to 3,000psi and ring gasket
between flow cross and upper master valve started leaking. Shut down N2 and close MV. Tighten flange nuts and test flange. Resume pumping N2 and pressure well up
to 4,000psi. RIH with GPT tools and found fluid level at 6,085’ and moving at ~4FPM. Bump pressure on well to maintain 4,000p si and continue monitoring movement.
Make final log run and found FL at 6,362’. POOH and pressure well up to 4,000psi. Lay down E-line for the night.
Report Number
21
Report Start Date
1/19/2025
Report End Date
1/20/2025
Last 24hr Summary
PTW/PJSM with crew. MIRU Yellow Jacket E-line, make up GPT tools. RIH and confirm fluid level was at the perfs, POOH with GPT. Make up 3.5” CIBP, RIH and set
CIBP at 6,780’. POOH lay down setting tool and make up 2”x6’ Geo Razor 6spf 60 degree phasing gun. RIH and correlate from 6,750-6,520’. Confirm tie in with geo and
perforate BEL 7 interval at 6761-6767’. POOH and lay down gun, make up GPT and confirm no fluid in TBG. Bleed WHP from 1,166psi to 166psi in 200psi increments
logging for fluid between each bleed. Made final log 20 minutes after last bleed and confirmed no fluid was entering well while WHP was rising. POOH while blowing
down TBG. Confirm LELs at tanks and line well up to production for test.
Field: Beaver Creek
Sundry #: 324-638
State: ALASKA
Rig/Service:
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Page 1/1
Well Name: BCU-011A
Report Printed: 1/31/2025
WellViewAdmin@hilcorp.com
Casing
Liner
Wellbore
Wellbore Name:
Sidetrack 1 Total Depth of Wellbore (ftKB):
3,244.00 Original KB/RT Elevation (ft):
179.00
RKB to GL (ft):
18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Liner Run Date:
11/5/2024 Set Depth (ftKB):
7,489.00
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf): Block Weight (1000lbf):
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
14.00 Ft/Min (ft/min):
8.92
Run Job:
241-00154 BCU 11A Completion, Drilling -
Completion, 10/31/2024 00:00
Set Depth (ftKB):
7,489.00 Set Depth (TVD) (ftKB):
6,727.8
Centralizer Detail:
109 total
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
Yes
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Liner Hanger 8.37 3.96 37.13 2,728.72 2,691.59
19 Blank Liner 3 1/2 2.99 9.20 L-80 593.08 3,321.80 2,728.72
Marker Jt 3 1/2 2.99 9.20 L-80 10.02 3,331.82 3,321.80
16 Blank Liner 3 1/2 2.99 9.20 L-80 496.87 3,828.69 3,331.82
RA Marker Jt 3 1/2 2.99 9.20 L-80 10.00 3,838.69 3,828.69
16 Blank Liner 3 1/2 2.99 9.20 L-80 497.70 4,336.39 3,838.69
Marker Jt 3 1/2 2.99 9.20 L-80 10.01 4,346.40 4,336.39
16 Blank Liner 3 1/2 2.99 9.20 L-80 498.93 4,845.33 4,346.40
RA Marker Jt 3 1/2 2.99 9.20 L-80 10.01 4,855.34 4,845.33
16 Blank Liner 3 1/2 2.99 9.20 L-80 498.91 5,354.25 4,855.34
Marker Jt 3 1/2 2.99 9.20 L-80 10.00 5,364.25 5,354.25
16 Blank Liner 3 1/2 2.99 9.20 L-80 499.21 5,863.46 5,364.25
RA Marker Jt 3 1/2 2.99 9.20 L-80 10.00 5,873.46 5,863.46
16 Blank Liner 3 1/2 2.99 9.20 L-80 499.86 6,373.32 5,873.46
Marker Jt 3 1/2 2.99 9.20 L-80 10.01 6,383.33 6,373.32
16 Blank Liner 3 1/2 2.99 9.20 L-80 497.63 6,880.96 6,383.33
RA Marker Jt 3 1/2 2.99 9.20 L-80 10.33 6,891.29 6,880.96
17 Blank Liner 3 1/2 2.99 9.20 L-80 531.28 7,422.57 6,891.29
Landing Collar 4 1/2 2.99 1.22 7,423.79 7,422.57
1 Blank Liner 3 1/2 2.99 9.20 L-80 31.10 7,454.89 7,423.79
Float Collar 4 1/2 2.99 1.26 7,456.15 7,454.89
1 Blank Liner 3 1/2 2.99 9.20 L-80 31.53 7,487.68 7,456.15
Float Shoe 3 1/2 1.32 7,489.00 7,487.68
Page 1/1
Well Name: BCU-011A
Report Printed: 1/31/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Liner, 7,489.00ftKB
Wellbore
Sidetrack 1
Job
241-00154 BCU 11A Drilling, Drilling -
Drilling, 10/23/2024 06:00
Cementing Start Date
11/5/2024
Cementing End Date
11/5/2024
Top Depth (ftKB)
2,704.0
Cement Stages
Stage Number: <Stage Number?>
Description
Liner Cement
Top Depth (ftKB)
2,704.0
Bottom Depth (ftKB)
7,490.0
Top Measurement Method
CBL
Pump Start Date
11/5/2024
Cement in Place At
11/5/2024
Final Circulating Pressure (psi)
1,100.0
Plug Bump Pressure (psi)
1,600.0
Full Return?
No
Returns During Job (%) Volume to Surface (bbl)
37.0
Volume Lost (bbl)
25.0
Bump Plug?
Yes
Float Failed?
Yes
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 11.00 30.0 4 Fox Cement
Lead Slurry Lead G 537 12.50 201.0 5 Fox Cement
Tail Slurry Tail G 109 15.30 24.0 3 Fox Cement
Displacement Displacemen
t
9.20 73.5 4 Fox cement
Post Job Calculations
Subtype Value
Crea— u"ot- l t
Regg, James B (OGC)
From:
Brooks, Phoebe L (OGC)
Sent:
Monday, December 30, 2024 1:11 PM
To:
Justin Gruenberg - (C)
Cc:
Regg, James B (OGC)
Subject:
RE: MIT Test Report
Attachments:
MIT BCU-11A 11-07-24 Revised.xlsx
Justin,
Attached is a revised report correcting the PTD #2241230 and moving the Waived by info to the Remarks. Please update
yourcopy. �—
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 ghoebe.brooks@alaska.Qov.
From: Justin Gruenberg - (C) <Justin.Gruenberg@hilcorp.com>
Sent: Thursday, November 7, 2024 5:06 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.waIlace @alaska.gov>
Subject: MITTest Report
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.
Attached is the MIT test form for BCU-11 A.
Justin Gruenberg
Hilcorp DSM — HEC 147
Office Phone (907) 776-6776
Cell Phone (907) 715-4195
The information contained in this email message is confidential and maybe legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the omvard transmission,
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
Submit to: 'im.reon0alaskis ooV'. AOGCC.Insoectors®alaska.00v: phoebeDmoks0alaskagov
OPERATOR: HIICDm Alaska, LLC
FIELD/UNIT/PAD: Beaver Creek/ Beaver Creek Unit/ Pad
DATE: 11/07/24
OPERATOR REP:
AOGCC REP:
chns.WallacerOalaska tiov
J� G�—
Well
11A '—
Pressures'. Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min.
PTO
2241230
Type Inj
N —
Tubing
0
2590
2570
2570
Type Test
P
Packer TVD
M88
BBL Pump
0.6
IA
0
0
0
0
Interval
O
Test psi
2500
BBL Return
0.5
OA
0
0
0
0
Result
P
Notes:
Post completion 3 lZ' tieback string and liner, Witness waived by Jim Regg.
Well
11A
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
2241230-
Type Inj
N
Tubing
0 —
210 .
210
210
Type Test
P
Packer WD
2688 —
BBL Pump
1,8
IA
0
2550
2550
2550 '
Interval
O
Test psi
2500
BBL Return
1.8
OA
0
0
0
0
Result
P
News:
Post completion 9-N� 0' x J 112' annulus. Tested IA Mies due to lack down gland nuts SaMW Ned back tightened gland nuts and re -tested sit Witness waived by Jim Reg,
well
Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type IN
Tubing
IType
Test
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inj
Tubing
Type Test
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Nown:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type lnj
Tubing
Type Tesl
Packer WO
BBL umpl
I IA
I
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Noce.:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Typ;Ird
Tubing
Type Test
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inj
Tubing
Type To
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
rlNs1ss:
TYPE INJ Ccdo
TYPE TEST codes
INTERVAL codes
Result Cotlea
W=Water
P=Pressure Teal
1=It Tom
P=pass
G='Gea
O= Other (dacnbe m Notes)
4=Four Year cyst,
F=foul
6=Slurry
V= Repuie. by Variance
1=lnconsufne
=Induslnel wesuv aler
O= Other(Istuxibein rwlea)
N = Not Inl.Pin,
Form 10426 (Revised 0112017)
MIT BCIJ-11A 11-07-24 Ret,leW
t�
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/21/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: BCU 11A
PTD: 224-123
API: 50-133-20521-01-00
FINAL LWD FORMATION EVALUATION LOGS (10/29/2024 to 11/03/2024)
PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
224-123
T39792
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.11.22 08:40:12 -09'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:McLellan, Bryan J (OGC)
To:Scott Warner
Cc:Donna Ambruz
Subject:RE: BCU-11A AOGCC 10-403 324-638 PTD 224-123 Approved 11-15-24
Date:Friday, November 15, 2024 11:44:00 AM
Scott
Hilcorp has approval to proceed with the perfs per the sundry.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Scott Warner <Scott.Warner@hilcorp.com>
Sent: Friday, November 15, 2024 9:56 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: FW: BCU-11A AOGCC 10-403 324-638 PTD 224-123 Approved 11-15-24
Bryan,
Attached is the CBL for BCU-11A. I am requesting approval to perforate as per Sundry.
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Friday, November 15, 2024 9:29 AM
To: Scott Warner <Scott.Warner@hilcorp.com>
Cc: Noel Nocas <Noel.Nocas@hilcorp.com>
Subject: BCU-11A AOGCC 10-403 324-638 PTD 224-123 Approved 11-15-24
FYI – Please distribute as necessary.
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. 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):
7,490'N/A
Casing Collapse
Structural
Conductor
Surface 1,950psi
Intermediate
Production 3,090psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; N/A ±2,700' MD/TVD; N/A, N/A
6,729'±7,454'±6,694'
Beaver Creek Beluga Gas
20"
13-3/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beaver Creek Unit (BCU) 11A237D
Same
7,000'3-1/2"
2253psi
±4,790'
N/A
Length
November 19, 2024
Tieback 3-1/2"
±7,490'
Perforation Depth MD (ft):
2,898' TOW
See Attached Schematic
3,450psi
2,898'
112'
2,198'
Size
112'
9-5/8"2,898'
2,187'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
±2,700'
5,750psi
2,198'
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
AKA 028083
224-123
50-133-20521-01-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Scott Warner, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
scott.warner@hilcorp.com
907-564-4506
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 writte n 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 10:02 am, Nov 07, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.11.06 17:51:07 -
09'00'
Noel Nocas
(4361)
324-638
Yes, for CT work only 11/7/24
Bryan McLellan
X
CT BOP test to 3000 psi.
Submit CBL and gain approval before perforating.
x -bjm
10-407
BJM 11/14/24
SFD 11/7/2024*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.11.15 08:24:49 -09'00'11/15/24
RBDMS JSB 111524
Well Prognosis
Well Name: BCU-11A API Number: 50-133-20521-01-00
Current Status: New Drill Well Permit to Drill Number: 224-123
Regulatory Contact: Donna Ambruz (907) 777-8305
First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C)
Maximum Expected BHP: 2915 psi @ 6625’ TVD (Based on 0.44 psi/ft gradient)
Max. Potential Surface Pressure:2253 psi (Based on 0.1 psi/ft gas gradient to surface)
Applicable Frac Gradient: 0.728 psi/ft using 14.0 ppg EMW FIT at the 9-5/8” int. casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.728-0.1) = 2253 psi / 0.628 = 3587‘ TVD
Top of Applicable Gas Pool: 6601’ MD/5855’ TVD (Beluga)
Well Status: New Drill Initial Completion
Brief Well Summary
BCU-11A is a new sidetrack well targeting the Upper Beluga sands. The objective of this sundry is to clean out
the tubing/liner with coil tubing/nitrogen and perforate the Upper Beluga 5-12 sands.
Wellbore Conditions:
- Max Inclination – 62.45° at 4,772’ MD
- Max DLS °/100’ – 6.8° at 3,265’ MD
- Liner will be full of ~9.1 ppg 6% KCl mud
- Tubing and IA will be displaced to 8.4 ppg CIW
- T & IA will be pressure tested to 2500 psi
Pre-Sundry Work:
1. Review all approved COAs
2. MIRU E-line and pressure control equipment
3. Log well with CBL tool in 3-1/2” liner (send results to AOGCC to review prior to perforating)
4. RDMO E-line
Procedure:
1. MIRU Coil Tubing and pressure control equipment
2. PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24hr notice for BOP test
3. RIH & clean out wellbore to ~7415 (~8’ above landing collar), displace liner to 8.4 ppg water
4. Reverse out wellbore with nitrogen, trap ~2000 psi on wellbore
a. ~65 bbls total wellbore volume
5. RDMO Coil Tubing
6. MIRU E-line and pressure control equipment
7. PT lubricator to 250 psi low / 3,000 psi high
8. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically
targeting 20% underbalance)
9. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up:
6601’ MD/5855’ TVD (Beluga)
14.0 ppg EMW FIT0.691 SFD
about 3813' TVD, 3849' MD SFD
0.591 SFD
* See accompanying email dated 11/7/2024. SFD
13.3* SFD
Well Prognosis
Below are proposed targeted sands in order of testing (bottom/up),
but additional sand may be added depending on results of these
perfs, between the proposed top and bottom perfs
Sand Top MD Btm MD Top TVD Btm TVD Interval
UBEL ±6,601' ±6,638' ±5,855' ±5,891' ±37'
BEL 5 ±6,659' ±6,681' ±5,912' ±5,933' ±22'
BEL 5 ±6,704' ±6,723' ±5,956' ±5,975' ±19'
BEL 6 ±6,726' ±6,733' ±5,978' ±5,985' ±7'
BEL 6 ±6,745' ±6,757' ±5,997' ±6,009' ±12'
BEL 7 ±6,759' ±6,769' ±6,011' ±6,020' ±10'
BEL 7B ±6,783' ±6,793' ±6,034' ±6,044' ±10'
BEL 7B ±6,798' ±6,811' ±6,049' ±6,062' ±13'
BEL 8 ±6,826' ±6,884' ±6,826' ±6,134' ±58'
BEL 8B ±6,889' ±6,895' ±6,139' ±6,144' ±6'
BEL 8C ±6,898' ±6,909' ±6,148' ±6,158' ±11'
BEL 8D ±6,939' ±6,950' ±6,188' ±6,199' ±11'
BEL 8D ±6,965' ±6,972' ±6,214' ±6,220' ±7'
BEL 9 ±6,978' ±6,988' ±6,226' ±6,236' ±10'
BEL 9 ±7,023' ±7,047' ±6,271' ±6,294' ±24'
BEL 10 ±7,063' ±7,069' ±6,310' ±6,316' ±6'
BEL 10 ±7,119' ±7,130' ±6,365' ±6,374' ±11'
BEL 11 ±7,138' ±7,161' ±6,384' ±6,407' ±23'
BEL 11 ±7,192' ±7,200' ±6,437' ±6,445' ±8'
BEL 11 ±7,226' ±7,237' ±6,470' ±6,481' ±11'
BEL 12 ±7,301' ±7,306' ±6,544' ±6,549' ±5'
BEL 12 ±7,334' ±7,340' ±6,577' ±6,582' ±6'
BEL 12 ±7,384' ±7,393' ±6,625' ±6,634' ±9'
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
i. Pending well production, all perf intervals may not be completed
ii. Note: A CIBP may be used instead of WRP if it is determined that no cement is
needed for operational purposes. 35ft will not be placed on each plug as these
zones are close together. If possible, the CIBP will be set 50’ above of the top of
the last perforated sand unless zones are too close together in which case the plug
will be set within 50’.
iii. If necessary, use nitrogen to pressure up well during perforating or to depress
water prior to setting a plug above perforations
10. RDMO
11. Turn well over to production & flow test well
12. Test SVS as necessary once well has reached stable flow rates
a. Notify state 48 hrs prior to testing within 5 days of stable production
Well Prognosis
Coil Procedure (Contingency)
1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24 hr notice for BOP test
2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth
3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Coil Tubing BOP Schematic
4. Standard Well Procedure – N2 Operations
_____________________________________________________________________________________
Updated by SRW 11-5-24
CURRENT SCHEMATIC
Beaver Creek Unit
Well: BCU-11A
PTD: 224-123
API: 50-133-20521-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20"Conductor 133 / K-55 / -19”Surf 112’
13-3/8”Surface 68 / K-55 / BTC 12.515”Surf 2,198’
9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 2,898’
(TOW)
3-1/2”Prod Liner 9.2 / L-80 / HYD-563 2.991”±2,700’7,490’
3-1/2”Tieback 9.2 / L-80 / EUE 8Rd 2.991”Surf ±2,700’
OPEN HOLE / CEMENT DETAIL
20”Driven
13-3/8”TOC @ Surface 820 sx
9-5/8"TOC @ Surface 1129 sx
3-1/2”TOC @ Liner Top ±2700’ L – 187 bbls / T - 23.3 bbls
JEWELRY DETAIL
No.Depth Item
1 ~1,500 Chemical Inj sub
2 ~2,700 Liner Top Packer
3 ~2,700 Seal Assembly
_____________________________________________________________________________________
Updated by SRW 11-5-24
PROPOSED
Beaver Creek Unit
Well: BCU-11A
PTD: 224-123
API: 50-133-20521-01-00
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20"Conductor 133 / K-55 / -19”Surf 112’
13-3/8”Surface 68 / K-55 / BTC 12.515”Surf 2,198’
9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 2,898’
(TOW)
3-1/2”Prod Liner 9.2 / L-80 / HYD-563 2.991”±2,700’7,490’
3-1/2”Tieback 9.2 / L-80 / EUE 8Rd 2.991”Surf ±2,700’
OPEN HOLE / CEMENT DETAIL
20”Driven
13-3/8”TOC @ Surface 820 sx
9-5/8"TOC @ Surface 1129 sx
3-1/2”TOC @ Liner Top ±2700’ L – 187 bbls / T - 23.3 bbls
JEWELRY DETAIL
No.Depth Item
1 ~1,500 Chemical Inj sub
2 ~2,700 Liner Top Packer
3 ~2,700 Seal Assembly
PERFORATION DETAIL
Zone Top MD Btm MD Top TVD Btm TVD Ft Date Status
UBEL ±6,601'±6,638'±5,855'±5,891'±37'TBD Proposed
BEL 5 ±6,659'±6,681'±5,912'±5,933'±22'TBD Proposed
BEL 5 ±6,704'±6,723'±5,956'±5,975'±19'TBD Proposed
BEL 6 ±6,726'±6,733'±5,978'±5,985'±7'TBD Proposed
BEL 6 ±6,745'±6,757'±5,997'±6,009'±12'TBD Proposed
BEL 7 ±6,759'±6,769'±6,011'±6,020'±10'TBD Proposed
BEL 7B ±6,783'±6,793'±6,034'±6,044'±10'TBD Proposed
BEL 7B ±6,798'±6,811'±6,049'±6,062'±13'TBD Proposed
BEL 8 ±6,826'±6,884'±6,826'±6,134'±58'TBD Proposed
BEL 8B ±6,889'±6,895'±6,139'±6,144'±6'TBD Proposed
BEL 8C ±6,898'±6,909'±6,148'±6,158'±11'TBD Proposed
BEL 8D ±6,939'±6,950'±6,188'±6,199'±11'TBD Proposed
BEL 8D ±6,965'±6,972'±6,214'±6,220'±7'TBD Proposed
BEL 9 ±6,978'±6,988'±6,226'±6,236'±10'TBD Proposed
BEL 9 ±7,023'±7,047'±6,271'±6,294'±24'TBD Proposed
BEL 10 ±7,063'±7,069'±6,310'±6,316'±6'TBD Proposed
BEL 10 ±7,119'±7,130'±6,365'±6,374'±11'TBD Proposed
BEL 11 ±7,138'±7,161'±6,384'±6,407'±23'TBD Proposed
BEL 11 ±7,192'±7,200'±6,437'±6,445'±8'TBD Proposed
BEL 11 ±7,226'±7,237'±6,470'±6,481'±11'TBD Proposed
BEL 12 ±7,301'±7,306'±6,544'±6,549'±5'TBD Proposed
BEL 12 ±7,334'±7,340'±6,577'±6,582'±6'TBD Proposed
BEL 12 ±7,384'±7,393'±6,625'±6,634'±9'TBD Proposed
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
1
McLellan, Bryan J (OGC)
From:McLellan, Bryan J (OGC)
Sent:Saturday, November 9, 2024 12:16 PM
To:Scott Warner; Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Hilcorp has approval to perform the CT work described in the sundry application. CT BOP test to 3000 psi.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Scott Warner <scott.warner@hilcorp.com>
Sent: Friday, November 8, 2024 1:46 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
No problem at all- apologies for the confusion.
We are hoping to run the CBL on this well tomorrow as the rig is moving oī loca Ɵon as we speak. If the CBL is successful
we would like to MIRU coil tubing on Sunday and plan to blow the well dry Monday but wai Ɵng on approval before
proceeding with the coil tubing work and perforaƟons of course.
Thanks,
ScoƩ Warner
Kenai – OperaƟons Engineer
Oĸce: (907) 564-4506
Cell: (907) 830-8863
2
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Thursday, November 7, 2024 4:09 PM
To: Scott Warner <scott.warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Thanks for your help ScoƩ.
Thanks Again and Be Well,
Steve Davies
AOGCC
From: Scott Warner <scott.warner@hilcorp.com>
Sent: Thursday, November 7, 2024 1:22 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Steve,
Just spoke with the drilling team and the daily summary informa Ɵon I reviewed while geƫng the frac gradient was
incorrect staƟng it was a 14.0 ppg EMW FIT which the drilling team has now corrected. It was in fact a 13.3 ppg EMW
LOT which the drilling team conĮrmed aŌer speaking with them.
Thanks,
ScoƩ Warner
Kenai – OperaƟons Engineer
Oĸce: (907) 564-4506
Cell: (907) 830-8863
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Thursday, November 7, 2024 11:45 AM
To: Scott Warner <scott.warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
ScoƩ,
I’m reviewing Hilcorp’s Sundry ApplicaƟon to perforate BCU-11A. I noƟce that the applicaƟon lists an FIT of
14.0 ppg EMW at the 9-5/8” casing shoe.
But thinking about this and checking back through my emails, I notice that the LOT/FIT reported for BCU-11A on
10/29/24 was given as 13.3 ppg.
For the current perforationg program this doesn’t appear to be significant, but to ensure AOGCC’s records are accurate,
which value is correct? If the correct value is not the originally reported 13.3 ppg, could you please provide a copy of
Hilcorp’s evaluation that shows why it has changed? I also believe that this was a leak-off test and not an FIT. Is that
correct?
Thanks and Be Well,
Steve Davies
AOGCC
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 conƱdential 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 Ʊrst saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or
steve.davies@alaska.gov
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
4
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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
1
Gluyas, Gavin R (OGC)
From:McLellan, Bryan J (OGC)
Sent:Saturday, November 9, 2024 12:16 PM
To:Scott Warner; Davies, Stephen F (OGC)
Cc:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Hilcorp has approval to perform the CT work described in the sundry application. CT BOP test to 3000 psi.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Scott Warner <scott.warner@hilcorp.com>
Sent: Friday, November 8, 2024 1:46 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
No problem at all- apologies for the confusion.
We are hoping to run the CBL on this well tomorrow as the rig is moving off locaƟon as we speak. If the CBL is successful
we would like to MIRU coil tubing on Sunday and plan to blow the well dry Monday but waiƟng on approval before
proceeding with the coil tubing work and perforaƟons of course.
Thanks,
ScoƩ Warner
Kenai – OperaƟons Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet.
2
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Thursday, November 7, 2024 4:09 PM
To: Scott Warner <scott.warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Thanks for your help ScoƩ.
Thanks Again and Be Well,
Steve Davies
AOGCC
From: Scott Warner <scott.warner@hilcorp.com>
Sent: Thursday, November 7, 2024 1:22 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
Steve,
Just spoke with the drilling team and the daily summary informaƟon I reviewed while geƫng the frac gradient was
incorrect staƟng it was a 14.0 ppg EMW FIT which the drilling team has now corrected. It was in fact a 13.3 ppg EMW
LOT which the drilling team confirmed aŌer speaking with them.
Thanks,
ScoƩ Warner
Kenai – OperaƟons Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Thursday, November 7, 2024 11:45 AM
To: Scott Warner <scott.warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] BCU-11A (Permit 224-123, Sundry 324-638) - Questions
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
ScoƩ,
I’m reviewing Hilcorp’s Sundry ApplicaƟon to perforate BCU-11A. I noƟce that the applicaƟon lists an FIT of
14.0 ppg EMW at the 9-5/8” casing shoe.
But thinking about this and checking back through my emails, I notice that the LOT/FIT reported for BCU-11A on
10/29/24 was given as 13.3 ppg.
For the current perforationg program this doesn’t appear to be significant, but to ensure AOGCC’s records are accurate,
which value is correct? If the correct value is not the originally reported 13.3 ppg, could you please provide a copy of
Hilcorp’s evaluation that shows why it has changed? I also believe that this was a leak-off test and not an FIT. Is that
correct?
Thanks and Be Well,
Steve Davies
AOGCC
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 Steve Davies at 907-793-1224 or
steve.davies@alaska.gov
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
4
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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Beaver Creek Field, Beluga Gas Pool, BCU-11A
Hilcorp Alaska, LLC
Permit to Drill Number: 224-13
Surface Location: 1124' FNL, 1481' FWL, Sec 34, T7N, R10W, SM, AK
Bottomhole Location: 2556' FSL, 247' FWL, Sec 34, T7N, R10W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this th day of September 2024.
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2024.09.30
08:26:03 -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: 7,238' TVD: 6,479'
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): 178.5' 15. Distance to Nearest Well Open
Surface: x-317294 y-2434069 Zone-.4 161' to Same Pool: 1170' to BCU-14B
16. Deviated wells:Kickoff depth: 2,900 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 61 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,538' 2,700' 2,699' 7,238' 6,479'
Tieback 3-1/2" 9.2# L-80 EUE 8RD 2,700' Surface Surface 2,700' 2,699'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
N/A
TVD
112'
2,198'
7,000'
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
BCU 11A
Beaver Creek Unit
Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Plugged
7,239'9-5/8"
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
2203
2633' FNL, 315' FWL, Sec 34, T7N, R10W, SM, AK
2556' FSL, 247' FWL, Sec 34, T7N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1124' FNL, 1481' FWL, Sec 34, T7N, R10W, SM, AK AKA 028083
18. Casing Program:Top - Setting Depth - BottomSpecifications
2851
GL / BF Elevation above MSL (ft):
Plugs (measured):
(including stage data)
L - 1048 ft3 / T - 130 ft3
Tieback Assy.
5,255'5,157'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
8,931'8,684'
LengthCasing
sundry #324-464
Size
Plugged
Conductor/Structural 20"112'
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
7,239'
Intermediate
112'
2,198'13-3/8"820 sx
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):
2,198'
1129 sx
10/17/2024
4432' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
2560
Cement Volume MD
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
Drilling Manager
09/10/24
Monty M
Myers
By Grace Christianson at 10:05 am, Sep 10, 2024
DSR-9/13/24
Submit FIT/LOT data within 48 hrs of performing test. Notify AOGCC if
communication with OA is observed during FIT/LOT.
A.Dewhurst 19SEP24
BJM 9/25/24
224-123 50-133-20521-01-00
BOP test to 2500 psi
*&:
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2024.09.30 08:26:14 -08'00'
09/30/24
09/30/24
RBDMS JSB 100124
BC 11A
PTD Program
Beaver Creek Unit
August 22, 2024
BC 11A
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 Proposed Schematic (Post plugging)............................................................................................6
7.0 Planned Wellbore Schematic........................................................................................................7
8.0 Drilling / Completion Summary...................................................................................................8
9.0 Mandatory Regulatory Compliance / Notifications....................................................................8
10.0 R/U and Preparatory Work........................................................................................................12
11.0 BOP N/U and Test........................................................................................................................13
12.0 Set Whipstock / Mill Window.....................................................................................................13
13.0 Drill 6-3/4” Hole Section..............................................................................................................15
14.0 Run 3-1/2” Production Liner ......................................................................................................16
15.0 Cement 3-1/2” Production Liner with YJOC............................................................................19
16.0 3-1/2” Liner Tieback Polish Run ................................................................................................23
17.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................23
18.0 BOP Schematic.............................................................................................................................24
19.0 Wellhead Schematic.....................................................................................................................25
20.0 Anticipated Drilling Hazards......................................................................................................26
21.0 Hilcorp Rig 167 Layout...............................................................................................................27
22.0 Choke Manifold Schematic.........................................................................................................28
23.0 Casing Design Information.........................................................................................................29
24.0 6-3/4” Hole Section MASP ..........................................................................................................30
25.0 Spider Plot....................................................................................................................................31
26.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................32
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1.0 Well Summary
Well BC 11A
Rig 169
Pad & Old Well Designation Beaver Creek –Pad 3 Sidetrack
Planned Completion Type 3-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Upper Beluga / Lower Sterling
Planned Well TD, MD / TVD 7238 MD / 6479’ TVD
PBTD, MD / TVD 7138’ MD
AFE Number
AFE Days
AFE Amount
Maximum Anticipated Pressure
(Surface)2203 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)2851 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB 178.5’
Ground Elevation 161’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
*Ensure at least 100’ of overlap between casing and liner
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellview.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Capture any out-of-scope work as NPT.
5.2 Afternoon Updates
x Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
x Submit a short operations update each morning by 7am in NDE –Drilling Comments
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills:
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com, and cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com, and
cdinger@hilcorp.com
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6.0 Proposed Schematic (Post plugging)
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7.0 Planned Wellbore Schematic
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8.0 Drilling / Completion Summary
BC 11A is an S-shaped sidetrack development well to be drilled from Beaver Creek Pad 3. 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 ~2900’MD. Maximum hole angle
will be ~61 deg. and TD of the well will be 7238’ TMD/ 6479’ TVD, ending with 10 deg inclination.
Vertical separation will be 2019 ft.
Drilling operations are expected to commence approximately October, 2024. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
Planned Pre-Rig operations (Separate Sundry):
- Abandon the BC 11 reservoir
-Set CIBP ~2950’
- Test casing to 3000 psi
General sequence of operations:
1. Rig 169 will MIRU over BC-11
2. NU BOPE and test to 2500 psi. (MASP 2203psi)
3. Set 9-5/8” 40# whipstock at 2900’ and 217 deg. Swap well to 9.0 ppg mud.
x Gyro required for WS set
4. Mill 8.5” window with 20’ of new formation.
5. Perform FIT to 14.0 ppg EMW
6. MU 6-3/4” bit with 4-3/4” tools (Triple Combo)
7. Drill 6-3/4” production hole to 7238’MD, performing short trips as needed
8. RIH w/ 3-1/2” liner. Set liner and cement. Circ wellbore clean.
9. Perform Clean out run to polish bore, LDDP
10. Perform liner lap test to 2500 psi.
11. Run 3-1/2” tie back completion.
12. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi
13. ND BOPE, NU tree and test void
Reservoir Evaluation Plan:
Production Hole: Triple Combo
9.0 Mandatory Regulatory Compliance / Notifications
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Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations and all
BLM regulations pertaining to 43 CFR 3171 or 3172. 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 BC 11A. Ensure to provide
AOGCC 24 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing.
x The testing of BOP equipment will be 250/2500 psi & subsequent tests of the BOP equipment will
be to 250/2500 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 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.
BLM Regulation Variance Requests:
x 43 CFR 3172.6(b)(1)(iii)
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.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
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: 250/2500
(Annular 2500 psi)
Subsequent Tests:
250/2500
(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 24 hours notice prior to testing BOPs.
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.
See updated BOP equipment summary
in attached email from S. McLaughlin
dated 9/24/24. -bjm
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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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10.0 R/U and Preparatory Work
1. Level pad and ensure enough room for layout of rig footprint and R/U.
2. Layout Herculite on pad to extend beyond footprint of rig.
3. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig.
5. 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
2900’-7238’8.8 –9.5 40-53 15-25 15-25 8.5-9.5 11.0
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 8.8 –9.5 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
6. Install 5-1/2” liners in mud pumps.
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x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
11.0 BOP N/U and Test
1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug
2.N/U to 11” 5M tubing spool
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.
4. Run BOPE test plug.
5. Test BOPE.
x Test BOP to 250/2500 psi for 5/10 min.
x Test VBR’s with 4-1/2”and 3-1/2 test joint
x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint
x Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
6. Mix 9.0 ppg 6% KCL PHPA mud system.
7. Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
12.0 Set Whipstock / Mill Window
Operation Steps:
1. Pull test plug. Set wear bushing in wellhead. Ensure ID of wear bushing > 6-3/4”.
2. Make up the WIS Mechanical set Whipstock and rig up to run GYRO.
Single ram will be omitted. -bjm
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3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock
assembly
¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly.
¾Avoid sudden starts and stops while running the whipstock.
¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch
the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly
when releasing the work string to RIH. These precautions are required to avoid any weakening of the
whipstock shear mechanisms and / or to avoid part / preset on the packer.
4. Run Gyro to obtain tray face. Orient whipstock as directed by the directional driller. The directional
plan specifies 217 deg Azmuith.
5. Set the top of the whipstock at ~2900’ MD (confirm depth after RWO)
x 7” Collars TBD after RWO
x Ref log:
x Parent well plugged to xxxx’
6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING
THE PLANNED FIT/LOT).
¾Use ditch magnets to collect the metal shavings. Clean regularly.
¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and
Kevlar gloves.
¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean
(circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and
make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface.
7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a
FIT to 14.0 ppg.
¾**Assuming the kick zone is at TD, a FIT of 13.0 ppg EMW gives a Kick Tolerance volume of 25 bbls with
9.5 ppg mud weight.
¾Monitor OA during FIT and report and change in pressure.
8. POOH and LD milling assembly
¾Once out of the hole, inspect mill gauge and record.
¾Flow check well for 10 minutes to confirm no flow:
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¾Before pulling off bottom.
¾Before pulling the BHA through the BOPE.
9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP
equipment is operable.
13.0 Drill 6-3/4”Hole Section
1. P/U 4-3/4” Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 6-3/4”bit
2. Ensure BHA components have been inspected previously.
3. Drift & caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
4. Ensure TF offset is measured accurately and entered correctly into the MWD software.
5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~200 gpm.
6. Production section will be drilled with a motor. Must keep up with 3.5 deg/100 DLS in the build
section of the wellbore.
7. TIH to window. Shallow test MWD on trip in.
8. Circulate well with 9.0 ppg mud to warm up mud until good 9.0 ppg in and out.
9. Drill 6-3/4”hole to 7238’ MD using motor assembly.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams.
Work through coal seams once drilled.
x Keep swab and surge pressures low when tripping.
x Ensure solids control equipment functioning properly and utilized to keep LGS to a
minimum without excessive dilution.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
x Minimize backreaming when working tight hole
10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for
cement calculations. CBU.
11. TOH with drilling assembly, handle BHA as appropriate.
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12. Confirm 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint.
14.0 Run 3-1/2”Production Liner
1. R/U Parker 3-1/2”casing running equipment.
x Ensure 3-1/2”Liner 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.
2. P/U shoe joint, visually verify no debris inside joint.
3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (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
4. Continue running 3-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint to the 7” window. Leave the centralizers free
floating.
5. Continue running 3-1/2” production liner
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6. Run in hole w/ 3-1/2” liner to the window.
7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
9. Circulate 2X bottoms up at shoe, ease casing thru window.
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.
11. Set casing slowly in and out of slips.
12. PU 3-1/2” X 9-5/8” BOT 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.
13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as
hole conditions dictate.
14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights.
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. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition
for cementing.
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15.0 Cement 3-1/2”Production Liner with YJOC
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 cementing 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.
2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
3. Pump 5 bbls spacer.
4. Test surface cmt lines to 4500 psi.
5. Pump remaining spacer.
6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight.
Job is designed to pump 40% OH excess.
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Estimated Total Cement Volume:
Cement Slurry Design:
Lead Slurry (6738’ MD to 2700’ MD)Tail Slurry (7238’ to 6738’ 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
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BridgeMaker II Lost Circulation
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.
8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP
entering into liner.
9. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
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.
11. Slack off total liner weight plus 30k to confirm hanger is set.
12. Do not overdisplace by more than 2x shoe track volume. Shoe track volume is 0.7 bbls.
13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression.
14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the
liner.
15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after
bumping plug and releasing pressure.
16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
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).
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.
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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.
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:
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.
22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to
the setting tool.
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.
Ensure to report the following on wellview:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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16.0 3-1/2”Liner Tieback Polish Run
1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to
perforating.
2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational
assurance test.
3. PU liner tieback polish mill assy and RIH on drillpipe.
4. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per BOT procedure.
5. POOH, and LDDP and polish mill.
17.0 3-1/2” Tieback Run, ND/NU, RDMO
1. Run 3-1/2” tubing completion assembly to above the liner top
x Tubing will be 3-1/2” L-80 9.2# EUE 8rd
x CIM depth tbd
2. Swap the well over to CI Water
3. Space out and land seal bore in tie back sleeve. RILDs.
4. Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min.
5. Install BPV in wellhead.
6. ND BOPE, NU tree, test void
7. Rig Down
Page 24 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
18.0 BOP Schematic
Superseded
Beaver Creek
2024 Rig 169
09//23/2024
11'’ 5M
Cameron Townsend
LWS type 2 7/8-5 variables
Blinds
DSA 11 5M x 7 1/16 5M
Page 25 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
19.0 Wellhead Schematic
Page 26 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
20.0 Anticipated Drilling Hazards
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.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 27 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
21.0 Hilcorp Rig 167 Layout
Page 28 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
22.0 Choke Manifold Schematic
Page 29 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
23.0 Casing Design Information
Page 30 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
24.0 6-3/4”Hole Section MASP
Page 31 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
25.0 Spider Plot
Page 32 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
26.0 Surface Plat (As-Built NAD27 & NAD83)
Page 33 Version PTD August 22, 2024
BC 11A
Drilling Procedure
PTD# xxxxx
F 0
$
!""
#!
#! $
#%
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000True Vertical Depth (1000 usft/in)-500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500
Vertical Section at 217.00° (1000 usft/in)
BCU 11A T1
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500BCU 11
13 3/8"
9 5/8"
3 1/2" X 6 3/4" Hole
500
1000
1500
2000
2500
3000
3500
40004500500055006000
65 00
700 0
723 8
BCU 11A wp03
KOP - Top of Whipstock - 2900'MD
Start 3.25 DLS - 3017'MD
Hold 61 INC - 4853'MD
Start 3.5 DLS - 5053'MD
Hold 10 INC - 6510'MD
TD - 7238'MD
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: Beaver CK Unit 11
Ground Level: 160.50
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 2434069.90 317294.5660° 39' 30.9827 N151° 1' 6.2527 W
SURVEY PROGRAM
Date: 2024-07-09T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
223.50 2900.00 BCU 11 (BCU 11) 3_MWD
2900.00 3300.00 BCU 11A wp03 (BCU 11A) 3_MWD+IFR1+MS+Sag
3300.00 7238.00 BCU 11A wp03 (BCU 11A) 3_MWD+IFR1+MS+Sag
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Beaver CK Unit 11, True North
Vertical (TVD) Reference:BCU_11A_PLAN_KB @ 178.50usft
Measured Depth Reference:BCU_11A_PLAN_KB @ 178.50usft
Calculation Method: Minimum Curvature
Project:Beaver Creek Unit
Site:Beaver Creek Unit Pad 3
Well: Beaver CK Unit 11
Wellbore:BCU 11A
Design:BCU 11A wp03
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 2900.00 0.76 49.18 2899.45 20.57 -9.00 0.00 0.00 -11.01 KOP - Top of Whipstock - 2900'MD
2 2917.00 1.34 217.05 2916.45 20.48 -9.04 12.30 172.26 -10.92
3 3017.00 1.34 217.05 3016.43 18.62 -10.45 0.00 0.00 -8.58 Start 3.25 DLS - 3017'MD
4 4852.70 61.00 217.00 4517.12 -706.35 -556.77 3.25 -0.05 899.19 Hold 61 INC - 4853'MD
5 5052.70 61.00 217.00 4614.08 -846.05 -662.04 0.00 0.00 1074.11 Start 3.5 DLS - 5053'MD66509.85 10.00 217.00 5761.59 -1499.74 -1154.63 3.50 180.00 1892.62 Hold 10 INC - 6510'MD
7 6583.89 10.00 217.00 5834.50 -1510.01 -1162.37 0.00 0.00 1905.48
8 7238.00 10.00 217.00 6478.68 -1600.72 -1230.73 0.00 0.00 2019.07 TD - 7238'MD
CASING DETAILS
TVD MD NameSize
2899.45 2900.00 9 5/8" KOP9-5/8
6478.68 7238.00 3 1/2" X 6 3/4" Hole3-1/2
TVDSS
2720.95
6300.18
-1700
-1600
-1500
-1400
-1300
-1200
-1100
-1000
-900
-800
-700
-600
-500
-400
-300
-200
-100
0
100
South(-)/North(+) (200 usft/in)-1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0
West(-)/East(+) (200 usft/in)
BCU 11A T1
BCU 11
9 5/8" KOP
3 1/2" X 6 3/4" Hole 750275
0
30003250
35
0
0
37
50
400
0
42
5
0
45
0
0
4750
5000
525
0
55
0
0
57
5
0
600
0
62
5
0
64
7
9
BCU 11A wp03
KOP - Top of Whipstock - 2900'MD
Start 3.25 DLS - 3017'MD
Hold 61 INC - 4853'MD
Start 3.5 DLS - 5053'MD
Hold 10 INC - 6510'MD
TD - 7238'MD
CASING DETAILS
TVD MD NameSize
2899.45 2900.00 9 5/8" KOP9-5/8
6478.68 7238.00 3 1/2" X 6 3/4" Hole3-1/2
Project: Beaver Creek Unit
Site: Beaver Creek Unit Pad 3
Well: Beaver CK Unit 11
Wellbore: BCU 11A
Plan: BCU 11A wp03
WELL DETAILS: Beaver CK Unit 11
Ground Level: 160.50
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 2434069.90 317294.56 60° 39' 30.9827 N 151° 1' 6.2527 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Beaver CK Unit 11, True North
Vertical (TVD) Reference:BCU_11A_PLAN_KB @ 178.50usft
Measured Depth Reference:BCU_11A_PLAN_KB @ 178.50usft
Calculation Method:Minimum Curvature
TVDSS
2720.95
6300.18
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0.001.002.003.004.00Separation Factor3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800Measured Depth (400 usft/in)BCU 5BCU 11WELL DETAILS:Beaver CK Unit 11 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 160.50+N/-S +E/-W Northing EastingLatittudeLongitude0.000.002434069.90317294.5660° 39' 30.9827 N151° 1' 6.2527 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Beaver CK Unit 11, True NorthVertical (TVD) Reference:BCU_11A_PLAN_KB @ 178.50usftMeasured Depth Reference:BCU_11A_PLAN_KB @ 178.50usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-07-09T00:00:00 Validated: Yes Version: Depth From Depth ToSurvey/PlanTool223.50 2900.00 BCU 11 (BCU 11) 3_MWD2900.00 3300.00 BCU 11A wp03 (BCU 11A) 3_MWD+IFR1+MS+Sag3300.00 7238.00 BCU 11A wp03 (BCU 11A) 3_MWD+IFR1+MS+Sag04080120160200Centre to Centre Separation (80 usft/in)3000 3200 3400 3600 3800 4000 4200 4400 4600 4800 5000 5200 5400 5600 5800 6000 6200 6400 6600 6800Measured Depth (400 usft/in)BCU 5BCU 5RDBCU 5RD2BCU 6 GLOBAL FILTER APPLIED: All wellpaths within 200' + 100/1000 of reference2900.00 To 7238Project: Beaver Creek UnitSite: Beaver Creek Unit Pad 3Well: Beaver CK Unit 11Wellbore: BCU 11APlan: BCU 11A wp03CASING DETAILSTVDMDNameSize2899.452900.009 5/8" KOP9-5/86478.687238.003 1/2" X 6 3/4" Hole3-1/2TVDSS2720.956300.18
1
McLellan, Bryan J (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Tuesday, September 24, 2024 1:10 PM
To:McLellan, Bryan J (OGC)
Cc:Cody Dinger
Subject:Change to pending BC-11 PTD program
Attachments:2024 Rig 169 BOP without single gate.docx
Bryan,
The PTD for BC-11 is currently under AOGCC review for approval. The wellhead height on Beaver Creek 11 will not
allow for an 11” four preventor BOP arrangement as planned. Adding gravel at BCU is diƯicult due to the BLM’s
requirement for certiƱed weed free gravel. Given the MASP of 2203 psi a three preventor arrangement is
acceptable per 20 AAC 25.035(e)(1)(A). No change to planned test pressures. A pipe ram will be tested for all drill
pipe and tubulars run.
Revised summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
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 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, Ʋoor valves, etc
Initial Test:
250/2500
(Annular 2500 psi)
Subsequent Tests:
250/2500
(Annular 2500 psi)
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
BEAVER CREEK BELUGA GAS
BCU 11A
224-123
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BEAVER CK UNIT 11AInitial Class/TypeDEV / PENDGeoArea820Unit50212On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241230BEAVER CREEK, BELUGA GAS - 80500NA1 Permit fee attachedYes AKA0280832 Lease number appropriateYes3 Unique well name and numberYes BEAVER CREEK, BELUGA GAS - 80500 - governed by CO 237D4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA20 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 pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes Note change to BOP equipment described in attached email29 BOPEs, do they meet regulationYes MPSP = 2203 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not recorded in nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normal pore pressures with potential for underpressured Beluga sands (Beluga-6,7,11)36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate9/19/2024ApprBJMDate9/25/2024ApprADDDate9/19/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 9/30/2024
