Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout223-008Nolan 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: 2/10/2026
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20260210
Well API #PTD #Log Date Log Company Log Type AOGCC
E-Set#
BRU 224-34T 50283202050000 225044 1/30/2026 AK E-LINE Perf T41349
CLU 11RD 50133205590100 225013 1/24/2026 AK E-LINE Perf T41350
CLU 11RD 50133205590100 225013 1/27/2026 AK E-LINE Plug/Perf T41350
KU 24-07RD2 50133203520200 225126 1/14/2026 AK E-LINE CBL T41351
KU 24-07RD2 50133203520200 225126 1/20/2026 AK E-LINE IPFOF T41351
MPI 2-74 50029237850000 224024 1/25/2026 AK E-LINE Whipstock T41352
MPU 1-36 50029236770000 220047 2/1/2026 AK E-LINE Packer T41353
MPU R-110 50029238260000 225085 10/24/2025 YELLOWJACKET RCBL T41354
NFU 14-25 50231200350000 210111 12/29/2025 YELLOWJACKET CBL T41355
SDI 3-15 50029217510000 187094 1/23/2026 AK E-LINE Whipstock T41356
SRU 214A-27 50133101580100 225133 2/4/2026 YELLOWJACKET SCBL T41357
SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF T41358
SRU 242-16 50133204050000 188157 1/24/2026 YELLOWJACKET PLUG-PERF T41359
SU 43-10 50133207390000 225107 1/19/2026 YELLOWJACKET
GPT-PLUG-
PERF T41360
SU 43-10 50133207390000 225107 12/31/2025 YELLOWJACKET SCBL T41360
Please include current contact information if different from above.
SRU 231-33 50133101630100 223008 7/31/2025 YELLOWJACKET PLUG-PERF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2026.02.10 14:51:05 -09'00'
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1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 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):
7,554'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
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
See Attached Schematic
Ryan LeMay, Operations Engineer
ryan.lemay@hilcorp.com
661-487-0871
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,403' TVD; N/A, N/A
6,355'2,971'
22"
11-3/4"
Swanson River Unit (SRU) 231-33CO 716A
Same
Size MD
4-1/2"
~962 psi
Swanson River Sterling-Upper Beluga Gas
September 23, 2025
2,578'2,578'
N/A
2,410'
3,344'
7,553'
Perforation Depth MD (ft):
2,743'
4-1/2"
7-5/8"2,743'
988'
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
28'
N/A
TVD Burst
N/A
8,430psi
988'
6,354'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 2:57 pm, Sep 09, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.09.09 14:16:13 -
08'00'
Noel Nocas
(4361)
325-550
DSR-9/10/25
CT BOP test to 2000 psi (contingent)
A.Dewhurst 10SEP25BJM 9/17/25
X
Dump bail 25' of cement on the newly installed CIBP at +/-3062' MD prior to adding perforations.
10-404
JLC 9/17/2025
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.17 14:12:55 -08'00'09/17/25
RBDMS JSB 091925
Well Name: SRU 231-33 API Number: 50-133-10163-01-00
Current Status: Gas Producer Permit to Drill Number: 223-008
First Call Engineer: Ryan LeMay (661) 487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506
Max. Expected BHP: 1235 psi @ 2731’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure: 962 psi Based on 0.1 psi/ft to surface
Applicable Frac Gradient: 0.68 psi / ft using 13.15 ppg EMW FIT at 7-5/8” casing shoe
Shallowest Allowable Perf TVD: MPSP / (0.68 - 0.1) = 962 psi / 0.58 = 1659’
Top of Applicable Gas Pool / PA: 2400’ MD / 2279’ TVD (Sterling / Upper Beluga)
Brief Well Summary
At the end of July 2025, the B5 sand was isolated with a CIBP at 3344’ MD and the B2 sand was perforated from
3112’ – 3132’ MD. Initial production from the B2 zone came on at 5 mmcfd / 0 bwpd / 926 FTP. At the end of
August 2025 water production increased significantly from the well accompanied by a sharp decreasing trend in
gas production. As of September 7, 2025 the well is producing at 2.9 mmcfd / 555 bwpd / 689 FTP
This is a pre-emptive Sundry application once the current B2 zone waters out and no longer produces sustained
gas production. At that time, a CIBP will be set to isolate water production and additional perforations will be
added in the B1 – A12 intervals.
Procedure
1. Push fluid away through open Sterling B2 perforations (3112’ - 3132’ MD) utilizing high pressure pad gas
or N2.
2. MIRU E-line unit. PT lubricator 250 psi low / 2000 psi high
3. RIH and set 4-1/2” CIBP @ + 3062’ MD.
4. Perforate the following intervals
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
Well Sand MD top
MD
Bottom TVD top
TVD
bottom Interval
SRU_231-33 A12 +2,748’ +2,752’ +2,532’ +2,536’ +4’
SRU_231-33 A12 +2,817’ +2,823’ +2,582’ +2,586’ +6’
SRU_231-33 A13 +2,852’ +2,858’ +2,607’ +2,611’ +6’
SRU_231-33 A13 +2,862’ +2,870’ +2,614’ +2,619’ +8’
SRU_231-33 A14 +2,880’ +2,904’ +2,627’ +2,644’ +24’
SRU_231-33 B1 +2,994’ +3,008’ +2,709’ +2,719’ +14’
SRU_231-33 B1 +3,013’ +3,025’ +2,723’ +2,731’ +12’
Dump bail 25' of cement on CIBP. -bjm
a. Correlate using Open Hole Correlation 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 zone produces 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 high pressure pad gas or N2 to pressure up well during perforating or to
depress water prior to setting a plug above perforations.
5. RDMO
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, 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 / 2000 psi high
i. Provide AOGCC 24hrs notice of BOP test.
b. Cleanout wellbore fill and / or blowdown well with nitrogen as necessary.
Attachments:
x Current Wellbore Schematic
x Proposed Wellbore Schematic
x Coil Tubing BOP Schematic
x Standard Well Procedure – N2 Operations
Updated by DMA 08-20-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B2 3,112’3,132’2,797’2,812’20’7/31/25 Open
B5 3,394’3,409’3,009’3,026’15’5/1/25 Isolated
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolated
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
7
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
6
2
22”
11-3/4”
9
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 3,344’3.958”4-1/2” CIBP (07/31/25)
4 3,850’3.958”4-1/2” CIBP w/ 38 ft of cement TOC 3,812’ (5/1/25)
5 4,002’3.958”4-1/2” CIBP (04/13/25)
6 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
7 5,600’3.958”4-1/2” CIBP (10/19/23)
8 5,700’3.958”4-1/2” CIBP (10/19/23)
9 6,150’3.958”4-1/2” CIBP (10/17/23)
10 6,312’3.958”4-1/2” CIBP (10/17/23)
11 6,353’3.958”4-1/2” Wireline Retrievable Plug
12 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
13 6,751’3.958”CIBP 4/25/23 -see note on cement
14 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
15 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
13
11
12
14
15
10
5
8
4
3
B2
Updated by RPL 09-08-25
SCHEMATIC
Proposed
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATION DEATILS
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
A12 +2,748’+2,752’+2,532’+2,536’+4’Proposed
A12 +2,817’+2,823’+2,582’+2,586’+6’Proposed
A13 +2,852’+2,858’+2,607’+2,611’+6’Proposed
A13 +2,862’+2,870’+2,614’+2,619’+8’Proposed
A14 +2,880’+2,904’+2,627’+2,644’+24’Proposed
B1 +2,994’+3,008’+2,709’+2,719’+14’Proposed
B1 +3,013’+3,025’+2,723’+2,731’+12’Proposed
B2 3,112’3,132’2,797’2,812’20’7/31/25 Isolate
B5 3,394’3,409’3,009’3,026’15’5/1/25 Isolated
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolated
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
8
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
7
2
22”
11-3/4”
10
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 +3,062’3.958”Proposed
4 3,344’3.958”4-1/2” CIBP (07/31/25)
5 3,850’3.958”4-1/2” CIBP w/ 38 ft of cement TOC 3,812’ (5/1/25)
6 4,002’3.958”4-1/2” CIBP (04/13/25)
7 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
8 5,600’3.958”4-1/2” CIBP (10/19/23)
9 5,700’3.958”4-1/2” CIBP (10/19/23)
10 6,150’3.958”4-1/2” CIBP (10/17/23)
11 6,312’3.958”4-1/2” CIBP (10/17/23)
12 6,353’3.958”4-1/2” Wireline Retrievable Plug
13 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
14 6,751’3.958”CIBP 4/25/23 -see note on cement
15 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
16 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
14
12
13
15
16
11
6
9
5
4
B2
A12 – B13
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. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,554 feet See Schematic feet
true vertical 6,355 feet N/A feet
Effective Depth measured 3,344 feet 2,570 feet
true vertical 2,971 feet 2,404 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth) LTP; N/A 2,570' MD/2,403' TVD N/A N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
4,790psi
7,500psi
6,880psi
8,430psi
988' (TOW) 988'
Burst Collapse
Production
Liner
2,743'
4,983'
2,578'
Casing
Structural
2,529'
6,354'
4-1/2"
2,743'
7,553'
2,578' 2,410'
28'Conductor
Surf Csg/Conductor
Int Csg/Surf Csg
22"
11-3/4:
28'
988'
measured
TVD
7-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-008
50-133-10163-01-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA028399
Swanson River / Sterling-Upper Beluga Gas
Swanson River Unit (SRU) 231-33
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
65
Size
28'
0 05286
0 1431977
926
Ryan Lemay, Operations Engineer
325-435
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
ryan.lemay@hilcorp.com
661-487-0871
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 8:12 am, Aug 21, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.08.20 17:14:42 -
08'00'
Noel Nocas
(4361)
BJM 10/3/25
Page 1/1
Well Name: SRF SRU 231-33
Report Printed: 8/6/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report
Wellbore API/UWI:50-133-10163-01-00 Field Name:Swanson River State/Province:ALASKA
Permit to Drill (PTD) #:223-008 Sundry #:325-435 Rig Name/No:
Jobs
Actual Start Date:7/23/2025 End Date:
Report Number
1
Report Start Date
7/31/2025
Report End Date
8/1/2025
Last 24hr Summary
Complete PTW / PJSM. MIRU YJ Eline. PT PCE to 250 psi low / 2000 psi high as per sundry. Set CIBP @ 3344' MD. Bleed WHP to 900 psi. Perforate ST B2 sands 3112'
- 3132'. WHP increased to 1048 psi. RDMO YJ Eline. Flow well to production.
psi high as per sundry. Set CIBP @ 3344' MD. Bleed WHP to 900
Updated by DMA 08-20-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467 / TVD = 6,280
TD = 7,554 / TVD = 6,355
RKB = 18.17
4 Type H BPV Profile
PERFORATIONS:
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status
B2 3,112 3,132 2,797 2,812 207/31/25 Open
B5 3,394 3,409 3,009 3,026 155/1/25 Isolated
B8 3,900' 3,923' 3,386' 3,402' 23' 12/26/24 Isolated
UB 35-0 4,052 4,059 3,499 3,505 711/8/23 Isolated
Bel_48-0 5,125 5,132 4,290 4,295 711/3/23 Isolated
Bel_49-5 5,531 5,540 4,603 4,610 910/19/23 Isolated
Bel_50-7 5,620 5,634 4,674 4,686 1410/19/23 Isolated
Bel_50-7 5,720 5,736 4,756 4,769 1610/18/23 Isolated
Bel_51-3 6,056 6,060 5,041 5,044 410/18/23 Isolated
Bel_51-3 6,065 6,071 5,049 5,054610/18/23 Isolated
Bel_51-3 6,085 6,090 5,066 5,071 510/18/23 Isolated
Bel_51-4 6,173 6,177 5,145 5,148 410/17/23 Isolated
Bel_52-9 6,315 6,320 5,271 5,275 54/27/23 Isolated
Bel_52-9 6,370 6,373 5,321 5,324 34/26/23 Isolated
TY_ 56-9 6,801 6,832 5,702 5,732 314/17/23 Isolated
TY_62-5 7,412 7,426 6,231 6,244 144/7/23 Isolated
TY_62-5 7,437 7,461 6,253 6,269 243/27/23 Isolated
RA 5,605
RA 6,092
7
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
22Conductor Weld Surf 28
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000Surf 988(TOW)
7-5/8Int Csg/Surf Csg 29.7 L-80 BTC 6.875Surf 2,743
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.9582,5707,553
4-1/2Tieback 12.6 L-80 DWC/C-HT 3.958Surface 2,578
6
2
22
11-3/4
9
JEWELRY DETAIL
No. Depth ID OD Item
1 988N/A 12.25Whipstock
2 2,570 4.875 6.540
Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78PBR. 3.833 Drift, Seal 1.63 off seat
3 3,3443.9584-1/2 CIBP (07/31/25)
4 3,8503.9584-1/2 CIBP w/ 38 ft of cement TOC 3,812 (5/1/25)
5 4,0023.9584-1/2 CIBP (04/13/25)
6 5,0753.9584-1/2 CIBP (11/08/23) w/ 35ft of cement
7 5,6003.9584-1/2 CIBP (10/19/23)
8 5,7003.9584-1/2 CIBP (10/19/23)
9 6,1503.9584-1/2 CIBP (10/17/23)
10 6,3123.9584-1/2 CIBP (10/17/23)
11 6,3533.9584-1/2 Wireline Retrievable Plug
12 6,5693.958CIBP 4/26/23 - w/ 35ft of cement
13 6,7513.958CIBP 4/25/23 -see note on cement
14 7,3623.958CIBP 4/17/23 - w/ 35ft of cement
15 7,4273.958CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75 CBL (3/3/23), shows solid cement from 1,258- 2743
4-1/2TOC @ 2,570 based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8
1
SRU 23-33
(Abandoned)
4-1/2
Notes:
6,751
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579. 17.5 of cement dumped when trying to work past obstruction at
6,579. Tag obstruction with gauge ring multiple times at 6,579 (dumped cement
below obstruction).
13
11
12
14
15
10
5
8
4
3
B2
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,554'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
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
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
N/A
TVD Burst
N/A
8,430psi
988'
6,354'
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
28'
7,553'
Perforation Depth MD (ft):
2,743'
4-1/2"
7-5/8"2,743'
988'
4-1/2"
~1066 psi
Swanson River Sterling-Upper Beluga Gas
August 5, 2025
2,578'2,578'
N/A
2,410'
3,812'3,320'
22"
11-3/4"
Swanson River Unit (SRU) 231-33CO 716A
Same
Size MD
See Attached Schematic
Ryan LeMay, Operations Engineer
ryan.lemay@hilcorp.com
661-487-0871
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,403' TVD; N/A, N/A
6,355'
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 8:40 am, Jul 23, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.07.22 14:56:07 -
08'00'
Noel Nocas
(4361)
325-435
DSR-7/23/25
Contingency CT BOP test to 2000 psi
X
10-404
BJM 7/23/25 A.Dewhurst 28JUL25*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.07.28 13:58:48 -08'00'07/28/25
RBDMS JSB 073125
Well Name: SRU 231-33 API Number: 50-133-10163-01-00
Current Status: Offline Gas Producer Permit to Drill Number: 223-008
First Call Engineer: Ryan LeMay (661) 487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506
Max. Expected BHP: 1368 psi @ 3026’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure: 1066 psi Based on 0.1 psi/ft to surface
Applicable Frac Gradient: 0.68 psi / ft using 13.15 ppg EMW FIT at 7-5/8” casing shoe
Shallowest Allowable Perf TVD: MPSP / (0.68 - 0.1) = 1066 psi / 0.58 = 1838’
Top of Applicable Gas Pool / PA: 2400’ MD / 2279’ TVD (Sterling / Upper Beluga)
Brief Well Summary
In May of 2025, a CIBP was set at 3850’ with 38’ of cement dump bailed on top of CIBP to isolate the B8 zone.
The B5 (3394’ – 3409’) was perforated and brought onto production. Initial production from the B5 zone came
on at ~3mmfcd. After approximately 2 weeks on production, well began producing a substantial amount of
water (1400 bwpd) with a steady decline in gas rate production. On 7/21/2025 gas production was down to
~500 mcfd and 2800 bwpd. As of 7/22/2025, gas production has ceased. Attempts are being made to recover
remaining rate but have currently been unsuccessful.
The intent of this Sundry is to isolate the currently open Sterling B5 perforations and add perforations in the
A13 – B2 sands.
Procedure
1. Push fluid away through open Sterling B5 perforations (3394’ - 3409’ MD) utilizing high pressure pad gas
or N2.
2. MIRU E-line unit. PT lubricator 250 psi low / 2000 psi high
3. RIH and set 4-1/2” CIBP @ + 3344’ MD.
4. Perforate the following intervals
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
Well Sand MD top
MD
Bottom TVD top
TVD
bottom Interval
SRU_231-33 A13 +2,852’ +2,858’ +2,607’ +2,611’ +6’
SRU_231-33 A13 +2,862’ +2,870’ +2,614’ +2,620’ +8’
SRU_231-33 A14 +2,880’ +2,904’ +2,627’ +2,644’ +24’
SRU_231-33 B1 +2,994’ +3,008’ +2,709’ +2,719’ +14’
SRU_231-33 B1 +3,013’ +3,025’ +2,723’ +2,732’ +12’
SRU_231-33 B2 +3,112’ +3,154’ +2,797’ +2,828’ +42’
SRU_231-33 B2 +3,163’ +3,169’ +2,835’ +2,839’ +6’
a. Correlate using Open Hole Correlation 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 zone produces 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 high pressure pad gas or N2 to pressure up well during perforating or to
depress water prior to setting a plug above perforations.
5. RDMO
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, 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 / 2000 psi high
i. Provide AOGCC 24hrs notice of BOP test.
b. Cleanout wellbore fill and / or blowdown well with nitrogen as necessary.
Attachments:
x Current Wellbore Schematic
x Proposed Wellbore Schematic
x Coil Tubing BOP Schematic
x Standard Well Procedure – N2 Operations
Updated by DMA 05-29-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B5 3,394’3,409’3,009’3,026’15’5/1/25 Open
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolated
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
6
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
5
2
22”
11-3/4”
8
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 3,850’3.958”4-1/2” CIBP w/ 38 ft of cement TOC 3,812’ (5/1/25)
4 4,002’3.958”4-1/2” CIBP (04/13/25)
5 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
6 5,600’3.958”4-1/2” CIBP (10/19/23)
7 5,700’3.958”4-1/2” CIBP (10/19/23)
8 6,150’3.958”4-1/2” CIBP (10/17/23)
9 6,312’3.958”4-1/2” CIBP (10/17/23)
10 6,353’3.958”4-1/2” Wireline Retrievable Plug
11 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
12 6,751’3.958”CIBP 4/25/23 -see note on cement
13 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
14 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
12
10
11
13
14
9
4
7
3
Updated by RPL 07-22-2025
SCHEMATIC
Proposed
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
A13 +2,852’+2,858’+2,607’+2,611’+6’Proposed
A13 +2,862’+2,870’+2,614’+2,620’+8’Proposed
A14 +2,880’+2,904’+2,627’+2,644’+24’Proposed
B1 +2,994’+3,008’+2,709’+2,719’+14’Proposed
B1 +3,013’+3,025’+2,723’+2,732’+12’Proposed
B2 +3,112’+3,154’+2,797’+2,828’+42’Proposed
B2 +3,163’+3,169’+2,835’+2,839’+6’Proposed
B5 3,394’3,409’3,009’3,026’15’5/1/25 Isolate
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolated
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
7
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
6
2
22”
11-3/4”
9
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 + 3,344’3.958”4-1/2” CIBP (Proposed)
4 3,850’3.958”4-1/2” CIBP w/ 38 ft of cement TOC 3,812’ (5/1/25)
5 4,002’3.958”4-1/2” CIBP (04/13/25)
6 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
7 5,600’3.958”4-1/2” CIBP (10/19/23)
8 5,700’3.958”4-1/2” CIBP (10/19/23)
9 6,150’3.958”4-1/2” CIBP (10/17/23)
10 6,312’3.958”4-1/2” CIBP (10/17/23)
11 6,353’3.958”4-1/2” Wireline Retrievable Plug
12 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
13 6,751’3.958”CIBP 4/25/23 -see note on cement
14 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
15 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
13
11
12
14
15
10
5
8
4
3
A13 – B2
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: 5/15/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250515
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf
T40412
END 2-72 50029237810000 224016 4/4/2025 READ CoilFlag
T40413
IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf
T40414
IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf
T40414
KU 33-08 50133207180000 224008 4/22/2025 AK E-LINE PPROF
T40415
MRU D-16RD 50733201830100 180110 4/21/2025 AK E-LINE Cement/Perf
T40416
NSU NS-06 50029230880000 202101 4/21/2025 AK E-LINE PPROF
T40417
NSU NS-19 50029231220000 202207 4/27/2025 AK E-LINE Perf
T40418
NSU NS-20 50029231180000 202188 4/24/2025 AK E-LINE Perf
T40419
NSU NS-23 50029231460000 203050 4/23/2024 AK E-LINE Packer
T40420
PBU 02-10B 50029201630200 200064 3/21/2025 BAKER SPN
T40421
PBU 06-19B 50029207910200 224095 3/1/2025 BAKER MRPM Borax
T40422
PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax
T40423
PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile
T40424
SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf
T40425
Revision Explanation: Processing report added
Please include current contact information if different from above.
T40425SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.16 08:15:21 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/08/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250508
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 241-26 50283201970000 224068 4/15/2025 AK E-LINE Perf
BRU 244-27 50283201850000 222038 4/19/2025 AK E-LINE Perf
IRU 11-06 50283201300000 208184 4/14/2025 AK E-LINE CIBP
PBU S-22B 50029221190200 197051 4/15/2025 AK E-LINE IPROF
SRU 231-33 50133101630100 223008 4/13/2025 AK E-LINE CIBP
PBU 14-33B 50029210020200 223067 1/22/2025 BAKER MRPM
END 1-65A 50029226270100 203312 4/15/2025 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON LDL
END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON MFC40
MPU R-105 50029238150000 225017 4/20/2025 HALLIBURTON CAST-CBL
NS-19 50029231220000 202207 4/12/2025 HALLIBURTON RBT
PBU 06-12B 50029204560200 211115 3/22/2025 HALLIBURTON RBT
PBU 07-22A 50029209250200 212085 3/31/2025 HALLIBURTON RBT
PBU B-30B 50029215420100 201105 4/9/2025 HALLIBURTON RBT-COILFLAG
PBU H-17A 50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG
PBU H-29B 50029218130200 225005 5/1/2025 HALLIBURTON RBT
PBU J-10B 50029204440200 215112 4/15/2025 HALLIBURTON RBT
PBU M-207 50029238070000 224141 4/21/2025 HALLIBURTON IPROF
PBU Z-25 50029219020000 188159 4/23/2025 HALLIBURTON IPROF
PBU Z-31 50029218710000 188112 4/25/2025 HALLIBURTON IPROF
Please include current contact information if different from above.
T40372
T40373
T40374
T40375
T40376
T40377
T40378
T40379
T40379
T40380
T40381
T40382
T40383
T40384
T40385
T40386
T40387
T40388
T40389
T40390
SRU 231-33 50133101630100 223008 4/13/2025 AK E-LINE CIBP
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.08 12:42:44 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
3. Address:Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,554 feet See Schematic feet
true vertical 6,355 feet N/A feet
Effective Depth measured 3,812 feet 2,570 feet
true vertical 3,320 feet 2,404 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth)LTP; N/A 2,570' MD/2,403' TVD N/A N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date:Contact Name:
Contact Email:
Authorized Title:Contact Phone:
4,790psi
7,500psi
6,880psi
8,430psi
988' (TOW)988'
Burst Collapse
Production
Liner
2,743'
4,983'
2,578'
Casing
Structural
2,529'
6,354'
4-1/2"
2,743'
7,553'
2,578'2,410'
28'Conductor
Surf Csg/Conductor
Int Csg/Surf Csg
22"
11-3/4:
28'
988'
measured
TVD
7-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-008
50-133-10163-01-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA028399
Swanson River / Sterling-Upper Beluga Gas
Swanson River Unit (SRU) 231-33
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
28'
0 02957
0 2600
1114
Ryan Lemay, Operations Engineer
325-257
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
ryan.lemay@hilcorp.com
661-487-0871
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 8:11 am, May 30, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.05.29 16:27:34 -
08'00'
Noel Nocas
(4361)
RBDMS JSB 053025
DSR-6/3/25BJM 9/19/25
Page 1/1
Well Name: SRF SRU 231-33
Report Printed: 5/7/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-10163-01-00 Field Name:Swanson River State/Province:ALASKA
Permit to Drill (PTD) #:223-008 Sundry #:325-257 Rig Name/No:
Jobs
Actual Start Date:4/24/2025 End Date:
Report Number
1
Report Start Date
5/1/2025
Report End Date
5/2/2025
Last 24hr Summary
PTW/PJSM. MIRU AK E-line. PT 250 psi low / 2,000 psi high. Run 3.75" GR/JB/GPT to 3,955' - fluid level at 3,865'. Set CIBP at 3,850' and dump bail 25 gal
cement (TOC 3812') Perforate B5 Sand (3,394' - 3,409') with well shut-in. Init SITP 908 psi, 15 min 1,117 psi. Turn well over to Prod Ops to flow test. SDFN.
Report Number
2
Report Start Date
5/2/2025
Report End Date
5/3/2025
Last 24hr Summary
PTW/PJSM. RDMO AK E-line.
Report Number
3
Report Start Date
5/5/2025
Report End Date
5/6/2025
Last 24hr Summary
MIRU slickline. PT lubricator 250 psi / 2000 psi. RIH w/ 2.25" x 5' DD bailer. Bobble at 2300' and 3400'. Set down and tag at 3793'. RIH w/ 2.83" gauge ring and tag
at 3803'. RDMO slickline.
Set CIBP at 3,850' and dump bail 25 gal
cement (TOC
p,p
Perforate B5 Sand (3,394' - 3,409
Updated by DMA 05-29-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B5 3,394’3,409’3,009’3,026’15’5/1/25 Open
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolated
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
6
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
5
2
22”
11-3/4”
8
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 3,850’3.958”4-1/2” CIBP w/ 37 ft of cement TOC 3,812’ (5/1/25)
4 4,002’3.958”4-1/2” CIBP (04/13/25)
5 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
6 5,600’3.958”4-1/2” CIBP (10/19/23)
7 5,700’3.958”4-1/2” CIBP (10/19/23)
8 6,150’3.958”4-1/2” CIBP (10/17/23)
9 6,312’3.958”4-1/2” CIBP (10/17/23)
10 6,353’3.958”4-1/2” Wireline Retrievable Plug
11 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
12 6,751’3.958”CIBP 4/25/23 -see note on cement
13 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
14 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
12
10
11
13
14
9
4
7
3
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,554'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
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
See Attached Schematic
Ryan Lemay, Operations Engineer
ryan.lemay@hilcorp.com
661-487-0871
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,404' TVD; N/A, N/A
6,355'4,226'
22"
11-3/4"
Swanson River Unit (SRU) 231-33CO 716A
Same
Size MD
4-1/2"
~1198 psi
Swanson River Sterling-Upper Beluga
May 7, 2025
2,578'2,578'
N/A
2,410'
5,040'
7,553'
Perforation Depth MD (ft):
2,743'
4-1/2"
7-5/8"2,743'
988'
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
28'
N/A
TVD Burst
N/A
8,430psi
988'
6,354'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
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
Noel Nocas
(4361)
Digitally signed by
Noel Nocas (4361)
Date: 2025.04.24
14:02:41 -08'00'
325-257
By Grace Christianson at 7:43 am, Apr 25, 2025
Perforate
DSR-4/29/25
Apr 25, 2025
10-404
CT BOP test to 2500 psi (contingency)
SFD 4/28/2025
May 7, 2025
BJM 4/28/25
X
RUSH
(Equipment available.) SFD
*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.04.30 14:56:00 -08'00'04/30/25
RBDMS JSB 050125
Well Name: SRU 231-33 API Number: 50-133-10163-01-00
Current Status: Offline Gas Producer Permit to Drill Number: 223-008
First Call Engineer: Ryan LeMay (661) 487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506
Max. Expected BHP: 1538 psi @ 3402’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure: 1198 psi Based on 0.1 psi/ft to surface
Applicable Frac Gradient: 0.68 psi / ft using 13.15 ppg EMW FIT at 7-5/8” casing shoe
Shallowest Allowable Perf TVD: MPSP / (0.68 - 0.1) = 1198 psi / 0.58 = 2065’ (No plans to perforate
above the top of applicable gas pool / PA)
Top of Applicable Gas Pool / PA: 2400’ MD / 2279’ TVD (Sterling / Upper Beluga)
Brief Well Summary
In December of 2024, Sterling B8 perforations were added from 3900’-3923’ MD. Production came on at
~3.2mmcfd until late February 2025 where production decline and increased water production were observed.
As of 4/9/2025 production had declined to ~800 mcfd / ~180 bbls water per day before loading up and dying on
4/10/2025. Attempts were made to bring back online without success. A CIBP was set at 4002’ MD in attempt
to isolate the UB35-0 from the Sterling B8 to determine if water production was coming from the UB35-0 zone.
The well was briefly brought online after setting CIBP producing > 200 bbl water per day rate and < 100 mcfd
gas rate before quickly loading up and dying. Multiple attempts have been made to bring well back online
without success.
The intent of this Sundry is to isolate the currently open Sterling B8 perforations and add perforations in the
A13 – B5 sands.
Procedure
1. MIRU E-line unit. PT lubricator 250 psi low / 2000 psi high
2. Determine fluid level and push fluid away through open Sterling B8 perforations (3900’ - 3923’ MD)
utilizing high pressure pad gas or N2.
3. RIH and set 4-1/2” CIBP @ + 3850’ MD. Dump bail minimum of 35’ of cement to + 3815’ MD.
4. Perforate the following intervals with 2.75” 60 degree phased guns
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
Well Sand MD top
MD
Bottom TVD top
TVD
bottom Interval
SRU_231-33 A13 2852 2858 2607 2619 6
SRU_231-33 A13 2862 2870 2607 2619 8
SRU_231-33 A14 2880 2904 2627 2644 24
SRU_231-33 B1 2994 3008 2709 2731 14
SRU_231-33 B1 3013 3025 2709 2731 12
SRU_231-33 B2 3112 3154 2797 2839 42
SRU_231-33 B2 3163 3169 2797 2839 6
SRU_231-33 B5 3394 3414 3009 3031 20
a. Correlate using Open Hole Correlation 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 zone produces 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 high pressure pad gas or N2 to pressure up well during perforating or to
depress water prior to setting a plug above perforations.
5. RDMO
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, 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 as necessary.
Attachments:
x Current Wellbore Schematic
x Proposed Wellbore Schematic
x Coil Tubing BOP Schematic
x Standard Well Procedure – N2 Operations
Updated by RPL 04-22-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B8 3,900'3,923'3,386'3,402'23'12/26/24 Open
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
7
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 4,002’3.958”4-1/2” CIBP (04/13/25)
4 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
5 5,600’3.958”4-1/2” CIBP (10/19/23)
6 5,700’3.958”4-1/2” CIBP (10/19/23)
7 6,150’3.958”4-1/2” CIBP (10/17/23)
8 6,312’3.958”4-1/2” CIBP (10/17/23)
9 6,353’3.958”4-1/2” Wireline Retrievable Plug
10 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
11 6,751’3.958”CIBP 4/25/23 -see note on cement
12 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
13 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
11
9
10
12
13
8
3
6
Updated by RPL 04-22-25
SCHEMATIC
Proposed
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
A13 2,852’2,858’2,607’2,619’6’Proposed
A13 2,862’2,870’2,607’2,619’8’Proposed
A14 2,880’2,904’2,627’2,644’24’Proposed
B1 2,994’3,008’2,709’2,731’14’Proposed
B1 3,013’3,025’2,709’2,731’12’Proposed
B2 3,112’3,154’2,797’2,839’42’Proposed
B2 3,163’3,169’2,797’2,839’6’Proposed
B5 3,394’3,414’3,009’3,031’20’Proposed
B8 3,900'3,923'3,386'3,402'23'12/26/24 Isolate
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
6
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
5
2
22”
11-3/4”
8
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 3,850’3.958”4-1/2” CIBP w/ 35 ft of cement ETOC 3815’ MD
4 4,002’3.958”4-1/2” CIBP (04/13/25)
5 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
6 5,600’3.958”4-1/2” CIBP (10/19/23)
7 5,700’3.958”4-1/2” CIBP (10/19/23)
8 6,150’3.958”4-1/2” CIBP (10/17/23)
9 6,312’3.958”4-1/2” CIBP (10/17/23)
10 6,353’3.958”4-1/2” Wireline Retrievable Plug
11 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
12 6,751’3.958”CIBP 4/25/23 -see note on cement
13 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
14 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
12
10
11
13
14
9
4
7
3
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
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:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:20250411 1634 APPROVAL SRU 231-33 PTD 223-008 Sundry 325-198 Program Change
Date:Friday, April 11, 2025 4:34:22 PM
From: Rixse, Melvin G (OGC)
Sent: Friday, April 11, 2025 4:33 PM
To: Scott Warner <Scott.Warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Lemay <Ryan.Lemay@hilcorp.com>
Subject: RE: SRU 231-33 PTD 223-008 Sundry 325-198 Program Change
Scott,
AOGCC approves your request below.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 Office
907-297-8474 Cell
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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov).
cc. Bryan, Ryan
From: Scott Warner <Scott.Warner@hilcorp.com>
Sent: Friday, April 11, 2025 2:58 PM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Ryan Lemay <Ryan.Lemay@hilcorp.com>
Subject: SRU 231-33 PTD 223-008 Sundry 325-198 Program Change
Mel,
This well has died since this procedure was written.
I am requesting a change in the procedure to change the retrievable plug to a CIBP. If that is
successful and rate comes back, we will flow the well. We would then dump bail cement on top of
the plug at a later date when more perforations are added up hole which will be included in a
separate sundry.
We plan to do this work tomorrow.
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
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, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. 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: Install Cap Soap String
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):
7,554'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
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
See Attached Schematic
Ryan Lemay, Operations Engineer
ryan.lemay@hilcorp.com
661-487-0871
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,404' TVD; N/A, N/A
6,355'4,226'
22"
11-3/4"
Swanson River Unit (SRU) 231-33CO 716A
Sterling-Upper Beluga
Size MD
4-1/2"
~1234 psi
Swanson River Beluga, Sterling-Up Bel, & Tyonek Gas Pools
April 11, 2025
2,578'2,578'
N/A
2,410'
5,040'
7,553'
Perforation Depth MD (ft):
2,743'
4-1/2"
7-5/8"2,743'
988'
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
28'
N/A
TVD Burst
N/A
8,430psi
988'
6,354'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:28 pm, Apr 02, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.04.02 11:08:41 -
08'00'
Noel Nocas
(4361)
325-198
BJM 4/3/25
DSR-4/2/25
10-404
A.Dewhurst 03APR25*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.04.04 09:48:27 -08'00'04/04/25
RBDMS JSB 040825
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
3. Address:Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,554 feet See Schematic feet
true vertical 6,355 feet N/A feet
Effective Depth measured 4,002 feet 2,570 feet
true vertical 3,462 feet 2,404 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth)LTP; N/A 2,570' MD/2,403' TVD N/A N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date:Contact Name:
Contact Email:
Authorized Title:Contact Phone:
Ryan Lemay, Operations Engineer
325-198
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
3250
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
ryan.lemay@hilcorp.com
661-487-0871
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
28'
123 019
0 81418
635
measured
TVD
7-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-008
50-133-10163-01-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA028399
Swanson River / Sterling-Upper Beluga Gas
Swanson River Unit (SRU) 231-33
Plugs
Junk measured
Length
Production
Liner
2,743'
4,983'
2,578'
Casing
Structural
2,529'
6,354'
4-1/2"
2,743'
7,553'
2,578'2,410'
28'Conductor
Surf Csg/Conductor
Int Csg/Surf Csg
22"
11-3/4:
28'
988'
4,790psi
7,500psi
6,880psi
8,430psi
988' (TOW)988'
Burst Collapse
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 3:15 pm, Apr 24, 2025
Noel Nocas
(4361)
Digitally signed by
Noel Nocas (4361)
Date: 2025.04.24
13:55:19 -08'00'
DSR-4/29/25BJM 6/26/25
rbdms sjb 081225
Page 1/1
Well Name: SRF SRU 231-33
Report Printed: 4/22/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-10163-01-00 Field Name:Swanson River State/Province:ALASKA
Permit to Drill (PTD) #:223-008 Sundry #:325-198 Rig Name/No:
Jobs
Actual Start Date:3/27/2025 End Date:
Report Number
1
Report Start Date
3/20/2025
Report End Date
3/20/2025
Last 24hr Summary
MIRU slickline for drift and tag. PT lubricator 250 psi low / 2000 high -good test. RIH and tag at 4987' with 2.5" x 4' DD bailer. RDMO slickline unit.
Report Number
2
Report Start Date
4/11/2025
Report End Date
4/11/2025
Last 24hr Summary
MIRU slickline unit. PT lubricator 250 psi low / 2500 psi high - good test. Ran 3.75" gauge ring to 4914'. Fluid level identified ~2570'. RDMO slickline unit.
Report Number
3
Report Start Date
4/13/2025
Report End Date
4/13/2025
Last 24hr Summary
PTW/PJSM. RU AK Eline. PT 250 psi low/ 2000 psi high - good test. RIH w/ 3.50" CIBP. Sit down 40' below swab. POOH and inspect tools, covered in foamy
soap. RIH w/ GPT, junk basket, and 3.75" GR. Tag at 4908' MD. POOH. RIH w/ 3.50" CIBP and set @ 4002' MD. POOH, secure well, RDMO.
Updated by RPL 04-22-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B8 3,900'3,923'3,386'3,402'23'12/26/24 Open
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Isolated
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
7
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 4,002’3.958”4-1/2” CIBP (04/13/25)
4 5,075’3.958”4-1/2” CIBP (11/08/23) w/ 35ft of cement
5 5,600’3.958”4-1/2” CIBP (10/19/23)
6 5,700’3.958”4-1/2” CIBP (10/19/23)
7 6,150’3.958”4-1/2” CIBP (10/17/23)
8 6,312’3.958”4-1/2” CIBP (10/17/23)
9 6,353’3.958”4-1/2” Wireline Retrievable Plug
10 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
11 6,751’3.958”CIBP 4/25/23 -see note on cement
12 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
13 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
11
9
10
12
13
8
3
6
Well Name: SRU 231-33 API Number: 50-133-10163-01-00
Current Status: Gas Producer Permit to Drill Number: 223-008
First Call Engineer: Ryan LeMay (661) 487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506
Max. Expected BHP: ~1584 psi @ 3505’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure ~1234 psi Based on 0.1 psi/ft to surface
Brief Well Summary
In December of 2024, Sterling B8 perforations were added from 3900’-3923’ MD. Production came on at
~3.2mmcfd until late February 2025 where production decline and increased water production were observed.
As of 3/26/2025 the well has declined to ~1.1mmcfd gas rate and increased to 176 bwpd.
The intent of this Sundry work is to attempt to shut off water production to increase gas productivity and
reliability in the well. If water shut off cannot be achieved, a capillary soap string will be installed for continuous
soap injection to maintain gas productivity while managing increased water production.
Notes Regarding Wellbore Condition
Current Production Status: 1092mcfd, 176 bwpd @ 298 psi (3/26/2025)
Open Perforations
x UB 35-0 (4052’-4059’ MD)
x Sterling B8 (3900’-3923’ MD)
Procedure
1. MIRU E-line. PT lubricator 250 psi low / 2000 psi high
2. RIH and set 4.5” RBP @ + 4002’ MD isolating UB 35-0 interval from Sterling B8 interval
3. RDMO E-line unit.
4. Production test well
Contingency Procedure # 1: If RBP is unsuccessful in shutting off water production and / or results in significant
gas production decline.
1. MIRU slickline unit. PT lubricator 250 psi low / 2000 psi high
2. RIH and retrieve RBP set at + 4002’ MD
3. RDMO slickline unit.
Contingency Procedure # 2: If unsuccessful in shutting off water production
1. MIRU capillary string unit.
2. Stab 3/8” capillary into wellhead pack-off assembly.
3. Install pack off and pressure test against swab valve to 2000 psi.
4. RIH with 3/8” capillary soap string to + 3900’ MD
5. Install slips and connect capillary tubing to chemical injection pump.
6. RDMO cap string unit.
7. Turn well over to production.
Attachments:
x Current Wellbore Schematic
x Proposed Wellbore Schematic
Updated by DMA 01-21-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B8 3,900'3,923'3,386'3,402'23'12/26/24 Open
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Open
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
6
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 5,075’3.958”3-1/2” CIBP (11/08/23) w/ 35ft of cement
4 5,600’3.958”4-1/2” CIBP (10/19/23)
5 5,700’3.958”4-1/2” CIBP (10/19/23)
6 6,150’3.958”4-1/2” CIBP (10/17/23)
7 6,312’3.958”4-1/2” CIBP (10/17/23)
8 6,353’3.958”4-1/2” Wireline Retrievable Plug
9 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
10 6,751’3.958”CIBP 4/25/23 -see note on cement
11 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
12 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
10
8
9
11
12
7
3
Updated by RPL 03-27-25
SCHEMATIC
Proposed
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B8 3,900'3,923'3,386'3,402'23'12/26/24 Open
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Open
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
6
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
8
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
22,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 4,002’3.958”4-1/2” RBP
4 5,075’3.958”3-1/2” CIBP (11/08/23) w/ 35ft of cement
5 5,600’3.958”4-1/2” CIBP (10/19/23)
6 5,700’3.958”4-1/2” CIBP (10/19/23)
7 6,150’3.958”4-1/2” CIBP (10/17/23)
8 6,312’3.958”4-1/2” CIBP (10/17/23)
9 6,353’3.958”4-1/2” Wireline Retrievable Plug
10 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
11 6,751’3.958”CIBP 4/25/23 -see note on cement
12 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
13 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
12
10
11
13
14
9
3
7
3/8”cap string
0’–3900’MD
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
3. Address:Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,554 feet See Schematic feet
true vertical 6,355 feet N/A feet
Effective Depth measured 5,040 feet 2,570 feet
true vertical 4,226 feet 2,404 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth)LTP; N/A 2,570' MD/2,403' TVD N/A N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date:Contact Name:
Contact Email:
Authorized Title:Contact Phone:
4,790psi
7,500psi
6,880psi
8,430psi
988' (TOW)988'
Burst Collapse
Production
Liner
2,743'
4,983'
2,578'
Casing
Structural
2,529'
6,354'
4-1/2"
2,743'
7,553'
2,578'2,410'
28'Conductor
Surf Csg/Conductor
Int Csg/Surf Csg
22"
11-3/4:
28'
988'
measured
TVD
7-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-008
50-133-10163-01-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA028399
Swanson River / Sterling-Upper Beluga Gas
Swanson River Unit (SRU) 231-33
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
28'
0 04048
0 1281
1179
Scott Warner, Operations Engineer
324-096
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
477
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
scott.warner@hilcorp.com
907-564-4506
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 1:08 pm, Jan 24, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.01.24 10:28:10 -
09'00'
Noel Nocas
(4361)
RBDMS JSB 012925
BJM 2/7/25 DSR-1/31/25A.Dewhurst 13FEB25
Page 1/1
Well Name: SRF SRU 231-33
Report Printed: 1/24/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:12/20/2024 End Date:
Report Number
1
Report Start Date
12/20/2024
Report End Date
12/21/2024
Last 24hr Summary
PTW/PJSM, PT 250/2000. RIH w/ 2'' bailer to 4048'kb broke thru bridge to 4100'kb did not tag. 3.75'' g-ring to 4052'kb broke thru to 4100'kb. RDMO
Report Number
2
Report Start Date
12/26/2024
Report End Date
12/27/2024
Last 24hr Summary
PTW/PJSM, PT 250/2000.-pass. Pressure up tbg with pad gas to 1059psi. Perforate Sterling B8 from 3900'-3923'. Observed a ~220 psi increase. RDMO & turn
over to OPs to flow.
Field: Swanson River
Sundry #: 324-096
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-008Permit to Drill (PTD) #:223-008
Wellbore API/UWI:50-133-10163-01-00
Updated by DMA 01-21-25
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
B8 3,900'3,923'3,386'3,402'23'12/26/24 Open
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Open
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
6
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 5,075’3.958”3-1/2” CIBP (11/08/23) w/ 35ft of cement
4 5,600’3.958”4-1/2” CIBP (10/19/23)
5 5,700’3.958”4-1/2” CIBP (10/19/23)
6 6,150’3.958”4-1/2” CIBP (10/17/23)
7 6,312’3.958”4-1/2” CIBP (10/17/23)
8 6,353’3.958”4-1/2” Wireline Retrievable Plug
9 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
10 6,751’3.958”CIBP 4/25/23 -see note on cement
11 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
12 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
10
8
9
11
12
7
3
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
From:McLellan, Bryan J (OGC)
To:Scott Warner
Subject:RE: SRU 231-33 AOGCC 10-403 324-096 PTD 223-008 Approved 02-27-24
Date:Thursday, December 19, 2024 3:22:00 PM
Attachments:image003.png
Scott,
Hilcorp has approval to make the proposed change as part of Sundry 324-096.
Regards
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: Thursday, December 19, 2024 1:45 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: SRU 231-33 AOGCC 10-403 324-096 PTD 223-008 Approved 02-27-24
Bryan,
We have Sundry 324-096 open for SRU 231-33 and I would like to execute this work with one change to the procedure.
The well is currently online and instead of setting a plug at 4027’, we would like to proceed without setting a plug and
perforate from bottoms up per table above
The only other sand open in this well is the UB 35-0 which is in the same Upper Beluga/Sterling gas pool as the
proposed perfs and a plug w/35’ of cement has already been set isolating the Beluga Gas Pool and Upper
Beluga/Sterling Gas Pool
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
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. Ifyou 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 strictlyprohibited. 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 promptlyand 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, oruse 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 recipientshould 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: 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):
7,554'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
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: Jake Flora, Operations Engineer
Contact Email:jake.flora@hilcorp.com
Contact Phone: 907-777-8442
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
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
N/A
TVD Burst
N/A
8,430psi
988'
Size
28'
7-5/8"2,743'
988'
MD
4-1/2"
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
March 1, 2024
2,578'2,578'
N/A
2,410'
7,553'
Perforation Depth MD (ft):
2,743'
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 231-33CO 716A
Sterling-Upper Beluga
6,354'4-1/2"
~1234 psi
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,404' TVD; N/A, N/A
6,355'7,467'6,280'
Swanson River Beluga, Sterling-Up Bel, & Tyonek Gas Pools
22"
11-3/4"
See Attached Schematic
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.02.16 09:31:02 -
09'00'
Noel Nocas
(4361)
324-096
By Grace Christianson at 11:50 am, Feb 20, 2024
BJM 2/27/24
DSR-2/21/24
10-404
SFD 2/23/2024*&:
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.02.27 16:31:00
-09'00'02/27/24
RBDMS JSB 022824
Well Name:SRU 231-33 API Number:50-133-10163-01-00
Current Status:Gas Producer Permit to Drill Number:223-008
First Call Engineer:Jake Flora (720) 988-5375 (c)
Second Call Engineer:Chad Helgeson (907) 229-4824 (c)
Max. Expected BHP: ~1584 psi @ 3505’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure ~1234 psi Based on 0.1 psi/ft to surface
Current Status: Producing Gas Well 1084mcfd, 1bwpd @ 657 psi (1/31/24)
Brief Well Summary
SRU 231-33 was sidetracked in March 2023 from SRU 23-33 and tested the wet Tyonek sands which were
plugged back and the well was completed in the Beluga sand which have produced from May till September
where rate has dropped to less than 50 mcf. In November 2023 the well was returned to production with
perforations in the Upper Beluga 35-0 sand with an IP of 1100 mcfd @ 1000 psi. The tubing pressure has been
steadily dropping since with the objective of this sundry is to increase productivity by plugging back the Beluga
and perforating sands in the Sterling.
Notes Regarding Wellbore Condition
Current Gross Perf Interval 4052-4059’ MD (3499-3505’ TVD)
Inclination 31-44 deg from 2000’ to TD
Last downhole operation Perforated UB 35-0 4052-4059’ (11/08/23)
Procedure
1. Review all approved COAs (BLM & AOGCC)
2. RU E-line, PT lubricator to 2000 psi
3. Depress fluid level with pad gas OR nitrogen
4. Set plug at ~4027’ (25’ over the highest open perforation)
5. Dump 35’ cement on plug
6. Perforate Sterling sands from the bottom up within the below intervals:
Zone
Top
MD Btm MD Top TVD Btm TVD TOTAL
Top Sterling Gas Pool 2400 2279
A13 2852 2870 2607 2619 18
A14 2880 2905 2627 2645 25
B1 2994 3024 2709 2731 30
B2 3112 3169 2797 2839 57
B5 3394 3425 3009 3031 31
B8 3900 3923 3386 3402 23
o increase productivity by plugging back the Beluga
and perforating sands in the Sterling.
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations
OR patch across the perforations.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Nitrogen SOP
Updated by DMA 11-15-23
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Open
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
6
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 5,075’3.958”3-1/2” CIBP (11/08/23) w/ 35ft of cement
4 5,600’3.958”4-1/2” CIBP (10/19/23)
5 5,700’3.958”4-1/2” CIBP (10/19/23)
6 6,150’3.958”4-1/2” CIBP (10/17/23)
7 6,312’3.958”4-1/2” CIBP (10/17/23)
8 6,353’3.958”4-1/2” Wireline Retrievable Plug
9 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
10 6,751’3.958”CIBP 4/25/23 -see note on cement
11 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
12 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
10
8
9
11
12
7
3
Updated by DMA 02-01-24
PROPOSED
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATION DETAIL
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
A13 ±2,852'±2,870'±2,607'±2,619'±18'Proposed TBD
A14 ±2,880'±2,905'±2,627'±2,645'±25'Proposed TBD
B1 ±2,994'±3,024'±2,709'±2,731'±30'Proposed TBD
B2 ±3,112'±3,169'±2,797'±2,839'±57'Proposed TBD
B5 ±3,394'±3,425'±3,009'±3,031'±31'Proposed TBD
B8 ±3,900'±3,923'±3,386'±3,402'±23'Proposed TBD
UB 35-0 4,052’4,059’3,499’3,505’7’11/8/23 Open
Bel_48-0 5,125’5,132’4,290’4,295’7’11/3/23 Isolated
Bel_49-5 5,531’5,540’4,603’4,610’9’10/19/23 Isolated
Bel_50-7 5,620’5,634’4,674’4,686’14’10/19/23 Isolated
Bel_50-7 5,720’5,736’4,756’4,769’16’10/18/23 Isolated
Bel_51-3 6,056’6,060’5,041’5,044’4’10/18/23 Isolated
Bel_51-3 6,065’6,071’5,049’5,054’6’10/18/23 Isolated
Bel_51-3 6,085’6,090’5,066’5,071’5’10/18/23 Isolated
Bel_51-4 6,173’6,177’5,145’5,148’4’10/17/23 Isolated
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
RA 5,605’
RA 6,092’
5
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
4
2
22”
11-3/4”
6
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
2A ±4,027’CIBP w/ 35’ cement – TOC @ ~3,992’
3 5,075’3.958”3-1/2” CIBP (11/08/23) w/ 35ft of cement
4 5,600’3.958”4-1/2” CIBP (10/19/23)
5 5,700’3.958”4-1/2” CIBP (10/19/23)
6 6,150’3.958”4-1/2” CIBP (10/17/23)
7 6,312’3.958”4-1/2” CIBP (10/17/23)
8 6,353’3.958”4-1/2” Wireline Retrievable Plug
9 6,569’3.958”CIBP 4/26/23 - w/ 35ft of cement
10 6,751’3.958”CIBP 4/25/23 -see note on cement
11 7,362’3.958”CIBP 4/17/23 - w/ 35ft of cement
12 7,427’3.958”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL (3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
10
8
9
11
12
7
3
2A
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: 1/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240112
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
END 1-27 50029216930000 187009 11/16/2023 YELLOWJACKET PERF
KALOTSA 4 50133206650000 217063 9/28/2023 YELLOWJACKET PERF
KALOTSA 8 50133207050000 222003 11/29/2023 YELLOWJACKET PERF
KBU 13-8 50133203040000 177029 11/5/2023 YELLOWJACKET PERF
KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT
KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF
KBU 11-08Z 50133206290000 214044 8/24/2023 AK E-LINE GPT/CIBP/PERF
KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL
KBU 23-05 50133206300000 214061 10/10/2023 AK E-LINE PLT
KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/PERF
MPU I-01 50029220650000 190090 11/18/2023 YELLOWJACKET PERF
PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF
PAXTON 7 50133206430000 214130 9/18/2023 YELLOWJACKET CBL
PAXTON 7 50133206430000 214130 10/7/2023 YELLOWJACKET PERF
SRU 224-10 50133101380100 222124 12/27/2023 YELLOWJACKET GPT-PLUG-PERF
SRU 224-10 50133101380100 222124 11/4/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT
SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT
SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF
SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL
Please include current contact information if different from above.
T38273
T38275
T38277
T38278
T38279
T38280
T38280
T38281
T38282
T38283
T38284
T38285
T38286
T38287
T38288
T38288
T38289
T38289
T38289
T38290
T38290
1/18/2024
T38287
SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT
SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.01.18
11:52:00 -09'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Coil/N2
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,554 feet See Schematic feet
true vertical 6,355 feet N/A feet
Effective Depth measured 7,467 feet 2,570 feet
true vertical 6,280 feet 2,404 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A
Packers and SSSV (type, measured and true vertical depth) LTP; N/A 2,570' MD/2,403' TVD N/A N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
Chad Helgeson, Operations Engineer
323-529
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
chelgeson@hilcorp.com
907-777-8405
N/A
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
28'
11 91059
0 2740
1087
measured
TVD
7-5/8"
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-008
50-133-10163-01-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
FEDA028399
Swanson River / Beluga Gas
Swanson River Unit (SRU) 231-33
Plugs
Junk measured
Length
Production
Liner
2,743'
4,983'
2,578'
Casing
Structural
2,529'
6,354'
4-1/2"
2,743'
7,553'
2,578' 2,410'
28'Conductor
Surf Csg/Conductor
Int Csg/Surf Csg
22"
11-3/4:
28'
988'
4,790psi
7,500psi
6,880psi
8,430psi
988' (TOW) 988'
Burst Collapse
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 12:45 pm, Nov 22, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.11.21 16:32:32 -
09'00'
Noel Nocas
(4361)
Rig Start Date End Date
E-Line 10/17/23 Future
10/17/2023 - Tuesday
YJ E-line meet at SRF office, obtain PTW, hold PJSM and discuss scope of work.
(Production had jumped gas from 14-33A well to 231-33 the night before).
Mobilize equipment to well site. SITP - 1334 psi
MIRU. M/U Wt. bar, GPT, setting tool and 3.50" OD CIBP. PU and PT 250 psi / 2500 psi.
CCL to top of plug = 21.5'. Open swab and RIH. Tagged PBTD at 6316'. Ran tie-in pass and corrected +5'. PBTD @ 6321'.
No fluid detected, set CIBP at 6312'. Confirmed plug set in place. POOH. M/U 2-3/4" x 4' gun (6spf/60D) with Gun Gamma
Ray/CCL (19.5' - CCL to T.S.). RIH, correlate, send log to RE/Geo. Bleed well down to 1200 psi.
Confirm on depth and shoot the BEL_51-4 interval at 6173'-6177'. (6153.5' CCL depth). POOH.
0/5/10/15 minute intervals - no change 1200 psi. Production operator opened flow line to system and relief valve tripped.
Bled well to 1000 psi. Operations trouble shoot valve. M/U GPT and RIH to plug depth 6312'. No fluid detected. Production
back online, flowed well down to 800 psi. SI, ran GPT and located fluid at 6268' (44' above CIBP at 6312').
Ops engineer orders to set CIBP above perfs. POOH w/ GPT.
OOH. M/U 3.50" OD CIBP. (13' CCL to plug). Open swab and RIH. Correlate and set CIBP at 6150'. PU and confirm plug set
in place. POOH. OOH. Secure well and SDFN.
Night ops to jump gas and repressure well to 1300 psi for continued add perf operations.
Daily Operations:
Hilcorp Alaska, LLC
Weekly Operations Summary
API Number Well Permit NumberWell Name
SRU 231-33 50-133-10163-01-00 223-008
10/18/2023 - Wednesday
YJ E-line arrive at SRF office, sign in, obtain PTW and hold PJSM. Mobe to location and M/U 2-3/4" switch guns (5' btm, 6'
middle, 4' top) with dual fire gamma ray/ccl.
CCL to T.S. - (5' gun) = 24' (6' gun) = 17' (4' gun) = 9.5'
PU tools and lube and move to well head.
SITP = 1350 psi. Open swab and RIH. Run correlation pass, confirm on depth, position (6061' CCL) and shoot gun #1 (BEL51-
3 @ 6085'-90'). Initial: 1257 psi / 15 min:1262.5 psi
Position Gun #2 (6048' CCL) and shoot (BEL51-3 @ 6065'-71') Initial: 1262.5 psi / 15 min: 1257.1 psi
Position Gun #3 (6046.5' CCL) and shoot (BEL51-3 @ 6056'-60') Initial: 1257.1 psi / 15 min: 1254 psi.
POOH. OOH. All shots fired / guns dry. M/U GPT and RIH. At 5000' begin flowing well from 1215 psi to 867 psi. SI and run
log pass. Detected fluid at 6072'. Run repeat pass, same. Send log to OE, orders to flow well to 500 psi and SI.
Detected fluid at 6063'. Repeat pass, same. Discuss results with OE with orders to perforate BEL_50-7 interval (5720'-
5736'). POOH. OOH. Build 2-3/4" x 16' gun (9' CCL to T.S.). M/U GR/CCL/perf gun and RIH. Run correlation pass and adjust -
1'. Position and shoot gun in BEL_50-7 interval 5720'-5736'.
Initial: 1209 psi 5 min: 1226 psi 10 min: 1229 psi 15 min: 1232 psi. POOH. OOH. All shots fired / gun dry. Secure well, SDFN
and turn over to production to flow back.
Rig Start Date End Date
E-Line 10/17/23 Future
Daily Operations:
Hilcorp Alaska, LLC
Weekly Operations Summary
API Number Well Permit NumberWell Name
SRU 231-33 50-133-10163-01-00 223-008
10/31/2023 - Tuesday
PJSM and PTW
Well flowing ~65MCFD @ 120psi
R/U YJ Eline
M/U weight bars and 1-11/16"OD GPT tool. Stab on well and PT Lubricator to 250psi/2500psi - Test Good,Open well and
RIH w/ GPT.
(Top open perf at 5,531', CIBP at 5600')
Fluid level observed at 3,680' with well flowing 65MCFD @ 120psi tubing pressure, Tag at 4,735'
Shut in well and pressure up with lift gas
Fluid level observed at 4,400' with SITP @ 1,000psi, Tag at 5,255'
Fluid level observed at 4,500' with SITP @ 1,800psi, Tag at 5,334'
Discuss with town, decision to evaluate with Slickline. POOH,RDMO YJ Eline
Assist production w/crane pick at facility. MIRU Pollard Slickline w/.125 wire. Ran 3" LIB, tagged @ 5,336' slm. Impression
shows sand & gun debris on low side of tubing. Made 4 runs w/3" Drive Down Bailer, worked bailer from 5,336' slm -
5,379' slm. Secure well and lay down Slickline for the night.
10/19/2023 - Thursday
YJ E-line arrive at SRF office, sign in, obtain PTW and hold PJSM. Travel to location.
RU, M/U GPT, setting tool w/ 3.50" OD CIBP (21.5' CCL to Plug)
Open swab (560 SITP) RIH. Locate FL @ 5605' (115' above perfs at 5720'-36'). Tagged PBTD at 6097' (53' above plug at
6150'). Jump line gas to well to depress fluid. Fluid moves at 2250 psi, follow fluid with GPT to perfs at 5720'-36'. Log tie-in
pass to set CIBP, confirm on depth and set plug at 5700'. POOH.
OOH. M/U 2-3/4" x 14' perf gun. (10.5' CCL to T.S.). Draw well down to 1200 psi. RIH, correlate, confirm on depth and fire
gun in BEL_50-7 interval at 5620'-5634'. Initial: 1197 psi 5 min: 1201 psi 10 min: 1201 psi 15 min: 1202 psi
POOH. All shots fired / Gun dry.
M/U 2-3/4" x 9' gun. (11.5' CCL to T.S.). RIH, correlate on depth and fire gun in BEL_49-5 interval at 5531'-40'. Initial: 1222
psi 5 min: 1420 psi 10 min: 1465 psi 15min: 1515 psi
OOH. All shots fired / bull plug damp. M/U GPT and RIH, flow test well at 500mcfd at 1609 psi. 16:00 hrs.
Locate FL w/ GPT at 5480' (51' above perfs) at 17:00 hrs. Run 2nd pass at 17:45 hrs FL @ 5440'. Orders to POOH and set
CIBP between BEL_50-7 and 49-5 perfs.
OOH. M/U setting tool w/ 3.50" OD CIBP to GPT tool. (21.5' CCL to plug). RIH, see FL at 5370', correlate and set plug at
5600'. POOH.
OOH. Secure well and RDMO YJ E-line. Job complete. Continue flowing well at 500 mcfd and monitoring pressure.
10/29/2023- Sunday
Rig Start Date End Date
E-Line 10/17/23 Future
Daily Operations:
Hilcorp Alaska, LLC
Weekly Operations Summary
API Number Well Permit NumberWell Name
SRU 231-33 50-133-10163-01-00 223-008
11/08/2023 - Wednesday
YJEL arrives at SRF office, signs in, obtains PTW and holds PJSM. Mobe to location.
RU equipment and M/U GPT. Move to well and PT 250psi
RIH and locate fluid level at 5200' (68' below perfs at 5125'-32' and 1150' below proposed perfs at 4052'-59'. PU and log
baseline GR/CCL from 4200'-2500' (+1' correction). POOH.
M/U CCL, wt. bar, #10 setting tool w/ 3.50" CIBP (14.5' CCL to plug). RIH, tie-in with collar locator, confirm on depth and
set plug at 5075' (50' above BEL48-0 perfs). POOH.
M/U 3" x 35' cement dump bailer, mix and fill bailer with 12 gal./15.3# cement slurry. RIH and dump on CIBP. POOH.
Rearm bailer, mix and fill with 12 gal/15.3# slurry, RIH and place cement on last deposit. Total fill - 35'. Est. TOC on plug =
Bleed well to 1200 psi. M/U CCL, wt. bar and 2-3/4" x 7' (6spf/60D) perf gun (13.5' CCL-T.S.) RIH, tie-in with collar locator
to baseline log, confirm on depth and
Initial: 1198 psi 5 min: 1202 psi 10 min: 1202 psi 15 min: 1202 psi . All shots fired, gun dry.
Secured well, RDMO E-line. Flowed well to 1087 psi at 450 mcf. SI and monitored build.
TP built to 1212 psi.
Slowly increased to 1MM at 1100 psi. Production to monitor flow test overnight.
11/03/2023 -Friday
YJEL arrives at SRF office, signs in, obtains PTW and holds PJSM. Crane and helper mobe to KGSF #1 and replace well
RU equipment and M/U GR/CCL to 2-3/4" x 7' (6spf/60D) perf gun. (13' CCL
T.S.). Move to well and PT 250psi/2500 psi. Pass. Well pressured with lift gas. Bleed well to 1100 psi. Open swab. RIH to
5250'. Run correlation pass and send to RE. Inconclusive correlation, rerun from 5447' to 5000'. Tie-in log still inconclusive
RIH and log base line gamma ray/CCL from PBTD to liner packer
at 2500'. Confirm correlation to OH log (Correct -2'). Fluid level at 4474'. POOH. M/U CCL, wt. bar, shock sub and 2-3/4" x
7' perf gun (15.5' CCL-T.S.). RIH, tie-in with collar locator and perforate BEL_48-0 interval 5125'-5132'. POOH. Initial: 1099
psi 5 min: 1220 psi 10 min: 1300 15 min: 1325 psi. ,OOH. All shots fired. Secure well. Begin flow back to sales.
RDMO EL to 224-10.
Updated by DMA 11-15-23
SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467 / TVD = 6,280
TD = 7,554 / TVD = 6,355
RKB = 18.17
4 Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
UB 35-0 4,052 4,059 3,499 3,505 711/8/23 Open
Bel_48-0 5,125 5,132 4,290 4,295 711/3/23 Isolated
Bel_49-5 5,531 5,540 4,603 4,610 910/19/23 Isolated
Bel_50-7 5,620 5,634 4,674 4,686 1410/19/23 Isolated
Bel_50-7 5,720 5,736 4,756 4,769 1610/18/23 Isolated
Bel_51-3 6,056 6,060 5,041 5,044 410/18/23 Isolated
Bel_51-3 6,065 6,071 5,049 5,054610/18/23 Isolated
Bel_51-3 6,085 6,090 5,066 5,071 510/18/23 Isolated
Bel_51-4 6,173 6,177 5,145 5,148 410/17/23 Isolated
Bel_52-9 6,315 6,320 5,271 5,275 54/27/23 Isolated
Bel_52-9 6,370 6,373 5,321 5,324 34/26/23 Isolated
TY_ 56-9 6,801 6,832 5,702 5,732 314/17/23 Isolated
TY_62-5 7,412 7,426 6,231 6,244 144/7/23 Isolated
TY_62-5 7,437 7,461 6,253 6,269 243/27/23 Isolated
RA 5,605
RA 6,092
5
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
22Conductor Weld Surf 28
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000Surf 988(TOW)
7-5/8Int Csg/Surf Csg 29.7 L-80 BTC 6.875Surf 2,743
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.9582,5707,553
4-1/2Tieback 12.6 L-80 DWC/C-HT 3.958Surface 2,578
4
2
22
11-3/4
6
JEWELRY DETAIL
No. Depth ID OD Item
1 988N/A 12.25Whipstock
2 2,570 4.875 6.540
Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78PBR. 3.833 Drift, Seal 1.63 off seat
3 5,0753.9583-1/2 CIBP (11/08/23) w/ 35ft of cement
4 5,6003.9584-1/2 CIBP (10/19/23)
5 5,7003.9584-1/2 CIBP (10/19/23)
6 6,1503.9584-1/2 CIBP (10/17/23)
7 6,3123.9584-1/2 CIBP (10/17/23)
8 6,3533.9584-1/2 Wireline Retrievable Plug
9 6,5693.958CIBP 4/26/23 - w/ 35ft of cement
10 6,7513.958CIBP 4/25/23 -see note on cement
11 7,3623.958CIBP 4/17/23 - w/ 35ft of cement
12 7,4273.958CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75 CBL (3/3/23), shows solid cement from 1,258- 2743
4-1/2TOC @ 2,570 based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8
1
SRU 23-33
(Abandoned)
4-1/2
Notes:
6,751
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579. 17.5 of cement dumped when trying to work past obstruction at
6,579. Tag obstruction with gauge ring multiple times at 6,579 (dumped cement
below obstruction).
10
8
9
11
12
7
3
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: Coil/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):
7,467'N/A
Casing Collapse
Structural
Conductor
Surf Csg/Conductor
Int Csg/Suf Csg 4,790psi
Production 7,500psi
Tieback
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
chelgeson@hilcorp.com
907-777-8405
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
FEDA028399
223-008
50-133-10163-01-00
Hilcorp Alaska, LLC
Proposed Pools:
N/A
TVD Burst
N/A
8,430psi
988'
Size
28'
7-5/8"2,743'
988'
MD
4-1/2"
See Attached Schematic
6,880psi
28'
2,529'
28'
988' (TOW)
October 10, 2023
2,578'2,578'
N/A
2,410'
7,553'
Perforation Depth MD (ft):
2,743'
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 231-33CO 716A
Same
6,354'4-1/2"
~1846 psi
4,983'
See Schematic
Length
LTP; N/A 2,570' MD/2,404' TVD; N/A, N/A
6,280'7,554'6,355'
Swanson River Beluga GP
22"
11-3/4"
See Attached Schematic
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 8:31 am, Sep 27, 2023
323-529
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.09.26 16:15:01 -
08'00'
Noel Nocas
(4361)
X
CT BOP test to 2500 psi
SFD
SFD 10/2/2023BJM 10/4/23
10-404
6,355'7,467'7,554'
DSR=9/27/23
6,280'
*&:JLC 10/5/2023
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.10.05
11:25:55 -08'00'10/05/23
RBDMS JSB 100523
Well: SRU 231-33
9/25/23
Well Name: SRU 231-33 API Number: 50-133-10163-01-00
Current Status: Gas Producer Permit to Drill Number: 223-008
First Call Engineer: Chad Helgeson (907) 777-8504 (O) (907) 229-4824 (C)
Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Max. Expected BHP: ~2,371 psi @ 5,258’ TVD Based on 0.452 psi/ft
Max. Potential Surface Pressure ~1846 psi @ 5,258’ TVD Based on 0.1 psi/ft to surface
Well Summary
SRU 231-33 was sidetracked in March 2023 from SRU 23-33 and tested the wet Tyonek sands which were
plugged back and the well was completed in the Beluga sand which have produced from May till September
where rate has dropped to less than 50 mcf.
The goal of this project is to continue perforating Beluga Sands to increase production from the well.
Notes Regarding Wellbore Condition
x Min ID = 3.833” (4-1/2” drift ID)
x Inclination 31-44 deg from 2000’ to TD
E-Line Perf
1. Review all approved COAs (BLM & AOGCC)
2. MIRU E-line and pressure control equipment. PT lubricator to 250psi low / 2,500 psi High
3. Ops pressure up well to 1500 psi.
4. PU and RIH with perf gun
5. Perforate Beluga sands per RE/Geo from bottom up testing each zone individually. Plan to stop
perforating
Sand Perforation
Top (MD)
Perforation
Bottom (MD)
Perforation
Top (TVD)
Perforation
Bottom (TVD)
Total Footage
(MD)
UB 35-0 ±4,052’ ±4,059’ ±3,499’ ±3,505’ ±7
Bel_36-8 ±4,100’ ±4,107’ ±3,535’ ±3,540’ ±7
Bel_48-0 ±5,125’ ±5,132’ ±4,290’ ±4,295’ ±7
Bel_49-5 ±5,532’ ±5,540’ ±4,604’ ±4,610’ ±8
Bel_50-7 ±5,620’ ±5,736’ ±4,674’ ±4,768’ ±116
Bel_51-1 ±6,000’ ±6,007’ ±4,991’ ±4,997’ ±7
Bel_51-3 ±6,056’ ±6,103’ ±5,041’ ±5,081’ ±47
Bel_51-4 ±6,173’ ±6,177’ ±5,145’ ±5,148’ ±4
Bel_51-7 ±6,286’ ±6,300’ ±5,246’ ±5,258’ ±14
a. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the
Geologist.
b. Record initial and 5/10/15 minute tubing pressures after firing
6. RD E-Line Unit and turn well over to production
7. Operations to flow well and test zones
Well: SRU 231-33
9/25/23
E-line Procedure (Contingency)
If any zone produces sand and/or water or needs isolated:
1. MIRU Eline
2. Pressure test equipment to 2,500 psi High/250 psi Low
3. Eline run PT to find fluid level (Pressure up with GL gas if needed)
4. Push fluid below perfs (verify fluid depth with PT tool)
5. PU 4-1/2” CIBP RIH and set above perfs
a. Note: All proposed perforations are in the same Pool / PA. A CIBP may be used instead of WRP
if it is determined that no cement is needed for operational purposes.
Coil tubing procedure (Contingency)
If plug does not get below proposed perfs and SL cannot bail enough fill:
a. MIRU Coiled Tubing Unit, PT BOPE to 2,500 psi High/250 psi Low
b. Provide AOGCC 24hrs notice of BOP test
c. PU CT jet nozzle and cleanout well to top of open perfs
d. POOH with coil
e. RDMO coil tubing
f. Complete Eline as necessary
Attachments:
1. Current schematic
2. Proposed Schematic
Updated by CJD 05-09-23
Current Schematic
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Open
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
2
22”
11-3/4”
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 6,353’4.500’4-1/2” Wireline Retrievable Plug
4 6,569’CIBP 4/26/23 - w/ 35ft of cement
5 6,751’CIBP 4/25/23 -see note on cement
6 7,362’CIBP 4/17/23 - w/ 35ft of cement
7 7,427’3.5”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original 22-33)
7-5/8"TOC @ Surface (3/3/23)
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
RA Tags 5,605 & 6,092’
Prior to plugging back any Beluga Sands, BLM needs to review plug depth and
cement volume to isolate between PAs. Be sure to get permission before
determining plug depth.
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstructionwith gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
5
3
4
6
7
Updated by CAH 09-22-23
PROPOSED
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
PERFORATIONS:
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
UB 35-0 ±4,052’±4,059’±3,499’±3,505’±7’TBD Proposed
Bel_36-8 ±4,100’±4,107’±3,535’±3,540’±7’TBD Proposed
Bel_48-0 ±5,125’±5,132’±4,290’±4,295’±7’TBD Proposed
Bel_49-5 ±5,532’±5,540’±4,604’±4,610’±8’TBD Proposed
Bel_50-7 ±5,620’±5,736’±4,674’±4,768’±116’TBD Proposed
Bel_51-1 ±6,000’±6,007’±4,991’±4,997’±7’TBD Proposed
Bel_51-3 ±6,056’±6,103’±5,041’±5,081’±47’TBD Proposed
Bel_51-4 ±6,173’±6,177’±5,145’±5,148’±4’TBD Proposed
Bel_51-7 ±6,286’±6,300’±5,246’±5,258’±14’TBD Proposed
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Isolated
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
2
22”
11-3/4”
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3A 6,310’3.958”4-1/2” CIBP – No cement (If needed)
3 6,353’3.958’4-1/2” Wireline Retrievable Plug
4 6,569’CIBP 4/26/23 - w/ 35ft of cement
5 6,751’CIBP 4/25/23 -see note on cement
6 7,362’CIBP 4/17/23 - w/ 35ft of cement
7 7,427’3.5”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original Wellbore 22-33)
7-5/8"TOC @ 75’ CBL(3/3/23), shows solid cement from 1,258- 2743’
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstruction with gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
5
3
4
6
7
5,605’
6,092’
3A
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230713-2
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
KBU 14-6y 50133205720000 207149 4/2/2023 HALLIBURTON TMD3D
MPU C-02 50029208660000 182194 4/29/2023
YELLOW
JACKET JET CUT
SRU 213B-15 50133206540000 215130 5/9/2023
YELLOW
JACKET GPT/PERF
SRU 213B-15 50133206540000 215130 4/24/2023
YELLOW
JACKET PLUG
SRU 231-33 50133101630100 223008 4/25/2023
YELLOW
JACKET PERF/GPT/PLUG
Please include current contact information if different from above.
T37845
T37846
T37847
T37847
T37848YELLOWSRU 231-33 50133101630100 223008 4/25/2023 PERF/GPT/PLUGJACKET
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.13
14:54:16 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230713
Well API # PTD # Log Date Log
Company Log Type AOGCC
Eset#
SRU 231-33 50133101630100 223008 3/27/2023 YELLOW
JACKET GPT/PERF
Please include current contact information if different from above.
T37843
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.13
10:57:09 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/11/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230712-2
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
MPU C-02 50029208660000 182194 4/29/2023
YELLOW
JACKET JET CUT
SRU 213B-15 50133206540000 215130 5/9/2023
YELLOW
JACKET GPT/PERF
SRU 213B-15 50133206540000 215130 4/24/2023
YELLOW
JACKET PLUG
SRU 231-33 50133101630100 223008 4/25/2023
YELLOW
JACKET PERF/GPT/PLUG
Please include current contact information if different from above.
T37840
T37841
T37841
T37842YELLOWSRU 231-33 50133101630100 223008 4/25/2023 PERF/GPT/PLUGJACKET
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.12
16:00:59 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 06/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230418
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
KU 12-17 50133205770000 208089 4/19/2023 YELLOW JACKET PERF
MPU C-42 50029231960000 204028 3/22/2023 YELLOW JACKET PERF
MPU E-19 50029227460000 197037 4/11/2023 YELLOW JACKET SCBL-CALIPER
MPU H-15 50029232840000 205159 3/8/2023 YELLOW JACKET PERF
MPU L-12 50029223340000 193011 4/2/2023 YELLOW JACKET CUT
PBU 01-31 50029216260000 186132 5/1/2023 YELLOW JACKET SCBL
PBU L-117 50029230390000 201167 3/5/2023 YELLOW JACKET SCBL
PBU V-02 50029232090000 204077 3/27/2023 YELLOW JACKET SCBL
SRU 231-33 50133101630100 223008 3/31/2023 YELLOW JACKET GPT-PERF
SRU 231-33 50133101630100 223008 4/14/2023 YELLOW JACKET GPT-PLUG-PERF
Please include current contact information if different from above.
T37746
T37747
T37748
T37749
T37750
T37751
T37752
T37753
T37754
T37754
SRU 231-33 50133101630100 223008 3/31/2023 YELLOW JACKET GPT-PERF
SRU 231-33 50133101630100 223008 4/14/2023 YELLOW JACKET GPT-PLUG-PERF
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.06.14
14:53:01 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 05/19/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
Cement Bond Log 03/03/2023
Radial Cement Bond Log 03/22/2023
Please include current contact information if different from above.
PTD: 223-008
T37665
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.05.23
13:04:33 -08'00'
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): Swanson River Field
GL: 140.2' 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
7-5/8" L-80 2,529'
4-1/2" L-80 6,354'
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:
001276 0
5/3/2023 24
Flow Tubing
0
944
N/A9440
644' FNL, 1458' FEL, Sec 33, T8N, R9W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
29.7#
12.6#
2,743'
Water-Bbl:
PRODUCTION TEST
3/27/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
345838
346224
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
9-7/8"
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2465375
SETTING DEPTH TVD
2465816
TOP HOLE SIZE
GPT/Perf Tie In, Mudlog, LWD: GR, PWD, EWR-M5, ALD, CTN, DDSR, CBL 3-3-23 & 3-22-23
N/A
988' MD / 988' TVD
N/A
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
344086 2462919
50-133-10163-01-00February 26, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
3/27/2023 223-008 / 323-154 / 323-252
N/A
SRU 231-33March 10, 20231717' FSL, 1715' FWL, Sec 33, T8N, R9W, SM, AK
158.2'
Tyonek GP / Beluga GP
A028399
7,554' MD / 6,355' TVD
6,353' MD / 5,306' TVD
1091' FNL, 1840' FEL, Sec 33, T8N, R9W, SM, AK
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
6-3/4"
L - 320 sx / T - 175 sx
2,404' L - 380 sx / T - 98 sx
Surface
4-1/2"
SIZE DEPTH SET (MD)
2,570' MD / 2,404' TVD
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,570'
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
2,578'
7,553'
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 2:19 pm, May 18, 2023
Completed
3/27/2023
JSB
RBDMS JSB 060723
GDSR-6/12/23
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval Bel 52-9 6,315' 5,271'
2203' 2122'
2986' 2703'
4030' 3483'
4066' 3510'
5246' 4382'
5542' 4612'
6305' 5263'
6382' 5331'
6387' 5536'
6742' 5650'
7394' 6216'
7521' 6327'
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:
TY 56-9
TY 62-5
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports
Authorized Title: Drilling Manager
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
INSTRUCTIONS
TY 64-4
TY 53-0
Mid Bel 36-0
Sterling A8
Mid Bel 49-4
Tyonek
Sterling B
Upper Beluga
Low Bel 50-6
Low Bel 52-9
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.
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
5.18.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.18 12:57:08 -08'00'
Monty M
Myers
Updated by CJD 05-09-23
Current Schematic
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
Bel_52-9 6,315’6,320’5,271’5,275’5’4/27/23 Open
Bel_52-9 6,370’6,373’5,321’5,324’3’4/26/23 Isolated
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,553’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,578’
2
22”
11-3/4”
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 6,353’4.500’4-1/2” Wireline Retrievable Plug
4 6,569’CIBP 4/26/23 - w/ 35ft of cement
5 6,751’CIBP 4/25/23 -see note on cement
6 7,362’CIBP 4/17/23 - w/ 35ft of cement
7 7,427’3.5”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original 22-33)
7-5/8"TOC @ Surface (3/3/23)
4-1/2”TOC @ 2,570’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
RA Tags 5,605 & 6,092’
Prior to plugging back any Beluga Sands, BLM needs to review plug depth and
cement volume to isolate between PAs. Be sure to get permission before
determining plug depth.
6,751’
CIBP set on 4/25/2023, while running in the hole with dump bailer full of cement,
tagged at 6,579’. 17.5’ of cement dumped when trying to work past obstruction at
6,579’. Tag obstructionwith gauge ring multiple times at 6,579’ (dumped cement
below obstruction).
5
3
4
6
7
Activity Date Ops Summary
2/20/2023 Traveled to Swanson River pad 23-33 and met with CCI grader operator and loader operator. 3 sand trucks enroute. Checked grade in various spots on pad for
backyard. Offloaded 3 trucks of sand and began grading for level, ordered 3 more truck loads. Notified Production Rep of need to remove above;ground
abandoned 2" gas lift line. Wait on sand trucks and CCI welder.;CCI welder arrived with Production Rep, cut off 2" line and capped same. Released welder,
offloaded 3 sand trucks and graded level. Staged rig mat trailers on pad. Rig's day crew marked pad for felt/liner lay out. Rolled out felt and liner, marked liner for
rig mats and started setting those,;Staged remaining available rig mats, light plants, and fuel cube on location;Set up light plants and heater, covered and thawed
rig mats w/ Tioga heater, chipped and cleared ice off rig mats w/ shovels and set same.;Broke tours w/ rig crews. Crew change at midnight. Cont. working on
removing ice and snow from rig mats in prep for setting rig modules at 07:00 hrs.
2/21/2023 Cont thawing rig mats of ice with tarps and heaters, CCI crew on location at 07:00 and warming up equipment, rig hands on 215 TS pad shoveling off snow berm
from rig modules, CCI moved small crane to 215 TS pad and LD derrick board windwalls, loaded pony walls and sub base, moved same to location.;Tried to
transport derrick but trailer wheels (5 axle) froze up, CCI worked on freeing trailer wheels, set pony walls on 231-33. Moved derrick, pit module, catwalk and boiler
skid off rig mats on 215 TS, cleaned rig mats and loaded same for transport to our location. Transported derrick to location.;Transported 2nd crane and rig mats
to 231-33, staged cranes, set iron roughneck HPU, set sub base on pony walls, set iron roughneck on rig floor, folded out walkways and installed stairs, set carrier
on sub, set derrick on carrier, stood V door windwall, stood derrick board windwalls, set doghouse;skid, set pit #1, set jig, set pump #1. Raised doghouse.;Set rig
HPU, set MP module #2. set pit module # 3 and raised roof. Set pit module #3. R/U suction line between pump modules. Raised roof on pit module #3. Plugged in
most of electrical throughout rig. R/U and secured lights on top of;rig modules. Warmed up gen skid w/ Tioga heater, fired gen #2, turned on lights to rig. CCI rig
support went to Pad-215 and cleaned up felt, liner, and misc. dunnage. Raised degasser in pit #4. Got heat to doghouse and removed snow from stairways.;Crew
change, held PTSM. R/U steam, air, and water jumper lines between pit module #2 and MP module #2. R/U same in pits along w/ roughneck heaters. Attempted
to get HYD to mast too raise mast w/ no luck. Currently trouble shooting HYD issue.;CCI rig support hauled to location, choke house, gen #3, wind wall rack, CCI
shack, Mud lab, hot box, centrifuge, centrifuge pump, and control panel. Currently cont. to R/U.
2/22/2023 Raise mast from headache rack, CCI clean up on pad 215 TS pad, set service shacks and connect to rig. Crane on location @ 07:00 and set choke house, hung
cellar tarps and staged heater in cellar box for welder, sanded pad and access road, set boiler skid, set centrifuge pump.;Quadco rep on location at 09:00,
assemble gas alarm system and function test same. Good. Set centrifuge control panel, set safety/ change shacks, set auxiliary fuel tank (empty), set centrifuge,
set MGS, Electric and Mechanics shack. Send 72 hour notice for Diverter function test to BLM @ 11:06.;Crew change, held PTSM. Welder and wellhead rep
continue to install new wellhead and complete, Install MGS vent stack, Install windwalls for pits and rig floor, spot camp trailers and set up, Connect trailers to
generator, CCI continue bringing equipment from Tyler pad, received confirmation from;BLM that they waive witness of Diverter function test @ 13:00.;Functioned
tested DWKS prior to spooling up drill line (ok). Spooled on drill line, slipped on an extra 7 wraps for a total of 90 wraps. Cleaned snow and ice off mast. Prepped
mast to scope, scoped mast. Unbridled and stored bridle lines, R/U camera system and coms. R/U IR HPU. Cont. w/ R/U in pits.;Set up mud dock for DP.;Crew
change, held PTSM. M/U wash pipe on top drive. R/U rigging and tailed TDS to rig floor in cradle. Hung TDS to blocks w/ dog bones. R/U HYD lines on TDS.
Connected service loop and Kelley hose to TDS. Cont. R/U in pits. Built wet dock for mud products. M/U steam jumper hoses for steam loop.;Installed roof over
centrifuge. Prepping MP's and working on rig acceptance check list.
2/23/2023 Continue working on Steam, Water and air lines. Handy Berm install berm around entire rig footprint, Load diesel and continue rigging up TDS, Install new
stocking on service loop lines and adjust as needed, Install T-Bar on torque tube and straighten torque tube, Third party personnel continue;rigging up equipment
and their shacks.Continue bringing in equipment from staging pad and placing on pad including mud products.;Pason arrives and meets with Toolpusher on plan
of checking entire system and getting it working as designed. Take on hot water to the boilers. Shovel snow from bottom of water tank and mud pits. Clean up all
snow in work areas. Disconnect service loop and re-configure orientation of lines.;Run TDS up & down mast to make sure Kelly hose & service loop were clocked
right. Cont. hauling water to rig tank and 400 bbl upright. Installed bails and adjusted link tilt clamps. Cont. staging up temp on boiler. Installed cutting shoots on
end of shakers. Cont. working on rig acceptance check;list. R/U elevators & tongs. Installed HYD mast raising cylinder covers. Warmed up MP #2. Replaced
frozen valves on water system.;Crew change, held PTSM. Opened up boiler @ 03:00 hrs., completed steam loop through out the rig, purged air out of heater,
installed steam trap disks. Finished water loop and got water circulating. Fired and warmed up MP #1, checked liner wash/ lube pump. Function tested mixing
equip on pit;module #3. Finished filling 400 bbl up right and rig tank. Started bring on water to pits to Hydro test pit system. Cont. R/U and working through rig
acceptance check list.
2/24/2023 Cleaned/ Organized connex boxes, Function test Pit #1 & #2, ALL ESD's, Catwalk, TOP Drive (Fix comms error for float function), Stage mud products for current
mud system to be built, Remove shipping beams, Dress out derrick board and rig floor for drilling, Install wear ring, Prep Diverter for N/U.;Submitted AOGCC
Diverter test notice @ 09:38 and AOGCC Brian Bixby responded and wants an update tomorrow afternoon. Updated BLM with a 72 hour notice of spud.;Worked
on N/U Diverter System, Install screens on shakers (API 120's), Started building first batch of 9.0ppg 6% KCL PHPA mud, Complete a pump parts inventory.
Pason rep continues completing installation. Checked pressures on accumulator bottles.;Cont. working on N/U diverter system. Installed flow line, chained down
stack. Installed knife valve. Hook up accumulator lines. Pressured up accumulator, Installed diverter vent line (98' from closest ignition source). Set diverter sign
at end of vent line and entrance of pad.;Cont. building first batch of new mud. Installed level sensor on water tank. Cont. w/ rig and working through rig acceptance
check list.;Crew change, held PTSM. Loaded MWD tool on drillers side on catwalk. Changed filters on camp gen. Finished building first 300 bbl batch of 6% KCL
PHPA mud. Loaded ODS catwalk racks w/ CDS-40 4.5" DP. Started build second batch of KCL mud. Strapped & tallied DP. Pulled test plug.;Currently function
testing diverter annular.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
SRF SRU 231-33
Swanson River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00028 SRU 231-33 Drilling
Spud Date:
2/25/2023 Diverter bag closing time of 25 seconds and knife valve 2 seconds. Pump fluid through MP #1/ MP#2 (Trouble shoot throttle valves and repair) Leak tight test of
surface lines, Good. Assure Iron Roughneck, Pull tongs & TDS are torquing properly. Confirmed Good. P/U and stand back Drill Pipe 35;stands. Breaking in re-
cut connections and continue building 9 ppg 6% KCL PHPA mud.;P/U and stand back 8 stands of CDS40 DP, Continue breaking in re-cut connections (Total of
29 pins and 19 boxes were re-cut), Continue building 9ppg 6% KCL PHPA mud, Work with welder repairing flowline, mud pump liner wash plates and link tilt
cylinders, Adjust the service loop on the top drive,;Function test fill pump. Good. Talley 18 jts of CDS40 HWDP, P/U and stand back 9 stands of HWDP. Verify
Rig Acceptance checklist complete. Accept rig at 18:00 hours.;Performed rig service- Greased blocks, TD, IR, DWKS, and crown. Inspected all handling equip.
for P/U BHA.;Removing ice & snow from rig mats and modules. Gathered and staged tools for BHA #1. MWD worked on testing there tools. Finished building new
6% KCL PHPA mud. Cleaned & organized pad. Installed new inspection cover gasket on small boiler.;Noticed gear oil increase in sight glass on TD gear box.
Performing multiple tests to decipher were the increase in oil is coming from.;Crew change, held PTSM. Cont. to trouble shoot top drive, remove snow & ice from
rig containment, and organize rig modules. Replaced suction rubbers in pill pit. Cleaned threads on spiral drill collars. Strapped and tallied BHA #1 tools.;At 02:50
hrs. had 1 cup of power steering fluid discharge onto the gravel of the pad due to a power steering hose bursting on the vac truck. Spill was immediately cleaned
up, and the proper personal have been notified.
2/26/2023 30 minute hazard hunt, Install kill line, Continue conditioning 9ppg 6% KCL PHPA mud, Drain stack and pull mouse hole from rotary, P/U 4-1/2" test joint and
function test 21-1/4" Annular Preventer, 35 seconds for closing and 2 seconds for knife valve opening.;AOGCC representative Brian Bixby arrive for witness, Test
all gas alarms, Good, Drawdown test with 21-1/4" Annular Preventer, Annular Preventer closed in 36 seconds and Knife valve opened in 2 seconds, Function test
Trip Tank, PVT alarms and flow paddle. All good.;Gather equipment for BHA #1 and get to rig floor. Prep tongs, Slips, Dog collar clamp and change
elevators.;P/U, M/U and RIH with BHA #1 Cleanout/ Gauge run for whipstock assembly. 10-5/8" window mill, Float sub, Two crossover subs, 8 6-3/8" spiral drill
collars, Two crossover subs and 9 stands of 4-1/2" CDS40 HWDP T/ 811'.;RIH with 4-1/2" CDS40 DP F/ 811' and tag CIBP @ 1022' with 20K down weight to
ensure Anchor sets on whipstock. P/U and circulate STS for a total of 1600 strokes, B/D TD and monitor well.;P/U and circulate STS for a total of 1600 strokes,
B/D TD and monitor well.;POOH F/ 1022' with BHA #1 and L/D mill assembly.;Bring tools to rig floor for Tri-Mill assembly from catwalk. M/U Tri-milling assy. w/
UBHO and racked back in derrick. P/U WIS mechanical set whip stock and set in false table. M/U tri-milling assy. to whip stock w/ 35K shear bolt as per WIS
rep.;RIH w/ whip stock, Tri-milling assy. DC, HWDP, and 2 stds. of 4.5" DP T/1013' at 20' per/min.;Crew change, held PTSM. P/U & M/U E-Kelley to string. R/U
AK E-line and Gyro data tools. RIH w/ Gyro data tool on E-line. Tagged UBHO at 925' WLM. Took 3 TF shots= 246. Re-orientated TF, worked pipe, took
reshot=26.5, re-orientated TF, worked pipe, took reshot=31.5. RIH F/1013'-T/1023';Set anchor w/ 14K down weight. Pulled whip stock up hole and set on depth at
1017' (Bottom of whip stock). Set anchor on whip stock w/ 14K down weight. P/U- 62K. Reshot TF w/ gyro tool= 33.92.;POOH w/ E-line/ Gyro data tools. L/D tool
and R/D E-line unit.;Sheared off whip stock bolt w/ 35K. TOW-988 BOW-1006.;Held PJSM on displacement. Displaced well over to 8.95 ppg 6% KCL PHPA mud.
(Total Disp. = 111 bbls).;Started Milling window at 988'. GPM-342 SPP-269 psi RPM-90 TQ-5K P/U-57K S/O-56K ROT-57K.
2/27/2023 Continue milling window F/ 988' T/ 1027' RPM 90, On bottom TQ 3.6 - 6.5K, Pump rate 450gpm, SPP 450 - 500 psi, Max gas 10 units, 248 lbs recovered metal,
TOW 988', BOW 1007'. Reamed through window until torque was minimal and dry drift window w/ no pump or rotation & observed 3-4K drag up & down.;Circulate
bottoms up @ 1027', Pull out of window to 985' and flowcheck for 10 minutes. Static, B/D Top Drive. P/U 59K S/O 57K.;POOH F/ 1027' T/ 308' standing back DP
and HWDP.;L/D DC and 10-5/8" Tri-milling BHA #2. Lead mill was a 7/16" under gauge, follow mill was a 7/16" under gauge, and dress mill was a 1/8" under
gauge. (See photos in well file);Cleaned & cleared rig floor. M/U Johnny whacker and flushed stack, recovered 2 lbs of metal on magnets.;TIH out of the derrick in
the hole, performing our make and break procedure on the newly recut 4.5" CDS-40 DP. Offline strapped & tallied 7-5/8 surface casing on staging pad (70
jts).;Crew change, held PTSM and our weekly safety meeting w/ the rig crew. Held PJSM w/ Sperry on P/U BHA #3. M/U 9-7/8" HBDS PDC bit, mud motor w/ 1.5
bend, DM, TM HOC, UBHO, Flex collars, HWDP, and jars. Circulated to warm BHA at 167'. Had to trouble shoot MWD transducer due to poor;communications
(Missed wired). Cont. P/U and RIH w/ remainder of BHA F/167'-T/983'.;R/U AK E-line and Gyro tools. RIH to UBHO sub, orientated TF. POOH and verified lead
indicator was crushed. Tied back E-line and Gyro tools in derrick.;Currently cont. to RIH F/983'-T/1007'.;Hauled: 0 bbl Solids to KGF G&I
Cumulative: 0 bbl
Hauled: 170 bbl Fluid to KGF G&I
Cumulative: 170 bbl
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 43 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 250 lbs
Cumulative: 250 lbs
2/28/2023 M/U TDS and drill 9-7/8" Surface hole F/ 1027' T/ 1168' shooting Gyros every connection. On Bottom TQ 2.5K, Off Bottom TQ 1K, WOB 2.5K, RPM 50, SPP
1181psi, Flow Rate 450gpm, Diff 110, Max Gas 90 units, MW in 9.0ppg, MW out 9.0ppg (15 lbs of metal recovered from shakers) P/U 52K, S/O 50K, ROT
50K;Circulate Bottoms Up to clean well, Shoot survey with Sperry, Gravity toolface achieved, Run Gyro to obtain survey. Confirmation we have enough room
underneath window for the Triple-Combo configuration.;Monitor Well, Static. POOH F/ 1168' T/ 859' with no overpulls observed coming back through window. P/U
49K, S/O 47K. R/D E-Line Sheeve and release E-Line and Gyro Representative.;POOH with BHA #3 F/ 859' T/ surface Bit graded a 1-1.;Rig Service, Grease Top
Drive, Blocks, Crown, Draworks and Iron Roughneck while monitoring well on trip tank.;P/U and M/U BHA #4 Triple Combo 9-7/8" Drilling assembly. Upload
MWD. Shallow pulse test. PJSM, Load sources. Continue RIH making up BHA #4 T/ 730', slide through window without issue, RIH t/ 1169' Fill pipe establish
parameters;Drill Ahead 9 7/8'' Hole section f/ 1169' t/ 1474' 400 gpm 950 psi 50 rpm 3k tq on bottom, PUW 55k SOW 55k ROT 55k max gas observed 120 units
clean surveys;Drill Ahead 9 7/8'' Hole Section f/ 1474' t/ 1840' 400 gpm 1000 psi 50 rpm 3.5k tq on bottom 2-5k WOB PUW 56k SOW 56k ROT 56k MW 9.15ppg
ECD 9.48 ppg;Hauled: 40 bbls Solids to KGF G&I
Cumulative: 40 bbls
Hauled: 120 bbls Fluid to KGF G&I
Cumulative: 290 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 15 lbs
Cumulative: 265 lbs
3/1/2023 Drill Ahead 9 7/8'' Hole Section F/ 1840' T/ 1970', 400 gpm, 1000 psi, 50 rpm, 3.5k tq on bottom, 2-5k WOB, Max Gas 106 units, P/U 56K, S/O 56K, ROT 56K,
MW 9.15ppg in and out, ECD 9.48 ppg, Circulate Bottoms Up while reciprocating string.;Break out TD and B/D. Monitor well for 10 minutes. Static.;POOH F/
1970' T/ 977' with no overpulls coming through window. Hole fill was 1 BBL over calculated. P/U 68K S/O 63K.;Service Crown, Blocks, Top Drive, Iron
Roughneck, Draworks, Gear Box, Drive Line, Floor Motor and Brake Linkage. Monitor well on trip tank with no gains or losses.;RIH F/ 977' T/ 1969' washing last
stand down with no problems. Correct pipe displacement observed. Sent 72 hour notice to BLM for BOPE Test and updated timing of running casing and
cementing.;Make Connection send Hi-Vis sweep and Drill Ahead 9 7/8'' Hole Section F/ 1970' T/ 2095', 400 gpm, 1000 psi, 60 rpm, 3.5k tq on bottom, 2-5k WOB,
Max Gas 50 units, P/U 63K, S/O 62K, ROT 56K, MW 9.0ppg in and out, ECD 9.35 ppg, Sweep back on time with no increase in cuttings.;Drill Ahead 9 7/8'' Hole
Section F/ 2095' T/ 2750', 420 gpm, 1000 psi, 60 rpm, 4-6K tq on bottom, 2-5k WOB, Max Gas 249 units, P/U 74K, S/O 65K, ROT 67K, MW 9.1ppg in and out,
ECD 9.48 ppg, Distance to Plan 7.42' 6.31' Low 3.91' Right.;Circulate bottoms up 413 gpm 833 psi obtain survey, flow check static, blow down topo drive.;POOH
f/ 2750' t/ 1970' with out issues.;RIH f/ 1970' t/ 2750' without issues no fill on bottom.;Pump HI Vis Sweep around no increase in cuttings back 430 stks late, Flow
check well static, blow down top drive.;POOH f/ 2750' t/ 736' no issues, stand back BHA and L/D BHA, Unload sources and Download MWD.;Hauled: 124 bbls
Solids to KGF G&I
Cumulative: 164 bbsl
Hauled: 371 bbls Fluid to KGF G&I
Cumulative: 661 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 12 lbs
Cumulative: 277 lbs
3/2/2023 Complete laying down BHA #4 after downloading MWD. Bit graded 1-1-WT-A-X-I-NO-TD.;Clean and Clear rig floor, Pull 15" ID wear bushing from starting head.
R/U casing tongs, elevators, slips and dog collar. M/U crossover for floor valve, M/U mud fill line and load casing on pipe racks.;PJSM for 7-5/8" casing run. M/U
Shoe Jt., Baker-Lok Jt. and Float Collar Jt. Attempt to check floats with no change in mud heighth in float collar jt. after stroking 60'. Connect XO and pump
through and verify floats are opening. B/D TD and remove floor valve. Re-Fill float collar jt.;and stroke up with blocks 60' lower down and confirm floats are
operating. B/O and B/D TD and surface lines. Remove floor valve from casing string.;PJSM, Continue running 7-5/8" L-80 29.7ppf BTC casing as per approved
tally F/ 129' T/ 2717' P/U 68K S/O 64K. P/U 7-5/8" Hanger/ Landing joint and land hanger @ 2743' Displacement calculated at 22.8 BBLs Actual 20.9
BBLs.;Circulate casing string bringing pump rate up to 233 GPM with 76 SPP, Break out crossovers and blow down top drive.;R/U cement head and cement lines,
PJSM, Fill lines, PT lines low and high, pump 60 bbls tuned prime spacer 10.5 ppg, drop bottom plug, pump 139 bbls Lead cement 12 ppg, pump 36 bbls tail
cement 15.8 ppg, drop top plug and kick out w/ 10 bbls of water, displace cement with 120.2 bbls of mud, bump;plugs 2 bpm 535 psi, pressure up t/ 1125 psi and
hold f/ 5 min, bleed off pressure and check floats bled back 1 bbl floats held CIP 21:10 hrs, R/D and Blow down lines wash up trucks t/ cuttings tank, no losses
through out job spacer and trace cement back to surface.;Drain stack and flush lines with black water, function bag and drain stack.;Service rig, grease blocks top
drive and draw works.;Continue Waiting on cement, house keeping and preventative maintenance around rig, grease choke manifold, change alternator belt on
mud pump #1, wash cellar and prep tools to nipple down, prep 5'' Liners for mud pumps.;Hauled: 9 bbls Solids to KGF G&I
Cumulative: 173 bbsl
Hauled: 132 bbls Fluid to KGF G&I
Cumulative: 793 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/3/2023 Continue waiting on cement, housekeeping and preventative maintenance around rig, Change oil/ filters on loader, review audit items and make repairs, Change
out dies and grabber box block, clean out MP #1 & MP#2 suction screens, Continue conditioning drilling mud.;PJSM with E-Line and R/U equipment for Temp Log
CBL on the 7-5/8" Casing.;RIH T/ 2600' md and log with temperature log CBL to Surface. Make two runs to get the best data.;R/D E-Line and tools.;Back out
landing joint and L/D on catwalk. Nipple down Diverter Assembly, remove riser and annular from cellar, remove T and DSA clean all flanges and cap ends put on
trailers f/ transport.;Install Pack off and Test Seals, N/U B Section of wellhead, test void and seal t/ 3000 psi f/ 15 min, prep choke and kill hose, spot in crane and
get BOP Stack spotted in.;Set BOP Stack in cellar and transfer to bridge cranes, R/D cranes and fold catwalk back into position, N/U BOP Stack, HCRs choke
and kill lines, install fittings and hook up koomey lines, Install flow box and riser, install flow line.;Hauled: 2 bbls Solids to KGF G&I
Cumulative: 175 bbsl
Hauled: 38 bbls Fluid to KGF G&I
Cumulative: 831 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/4/2023 Install flow box and bell nipple. Open all ram doors and install 2-7/8" x 5" VBRs in upper and lower pipe ram cavities and blind rams in cavity between the pipe
rams. Function test blind rams. Install test plug with 4-1/2" test joint. Function test Annular Preventer, UPRs and LPRs. AOGCC request 5K.;Rig up all testing
equipment, Flood stack and purge all lines with 70 water for testing.;Shell test to 250psi low and 5000psi high for shell test. Leaking re-torque flange at top of
tubing head with sweeney wrench. Attempt again and observe UPR door ODS and electric choke leaking, tighten with hammer wrench. Quadco test gas alarms
for AOGCC and BLM representatives.;Attempt again and observe choke hose flange leaking, tighten with hammer wrench, Tighten all connections on choke and
kill sides of mud cross. Shell test against UPRs T/ 250psi and 5000psi, Good Test.;Test BOPE with 4-1/2" test joint 250psi low for 5 charted minutes and high to
5000psi for 10 charted minutes for all rams and valves. Test Annular Preventer T/ 250psi low for 5 charted minutes and high 2500psi for 10 charted minutes with
AOGCC Bob Noble and BLM Travis Marshal. Had 2 FP Annular;function retest good, Blind rams - function retest same open doors found rolled rubber
straightened out and put back together retested good.;R/D test equipment, pull test plug.;R/U and test casing t/ 3500 psi f 30 min pumped in 1.53 bbls bled back
1.4 bbls.;Blow down lines and R/D all test equipment, set wear ring, Break down TIW and Dart, R/U to P/U DP.;RIH P/U DP from racks f/ surface to 2520' 80 jts
total, POOH racking Back DP.;Clean and clear floor, prep to change top drive motor.;Hauled: 0 bbls Solids to KGF G&I
Cumulative: 175 bbls
Hauled: 0 bbls Fluid to KGF G&I
Cumulative: 831 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/5/2023 Service Crown, Blocks, Top Drive, Iron Roughneck, Draworks, Gear Box, Drive Line, Floor Motor and Brake Linkage. Monitoring well on trip tank. Static.;PJSM
for Rineer motor change out on Top Drive while monitoring well on trip tank. Static. Lock out Top Drive and Floor motor. Disconnect Top Drive HPU lines and
remove Rineer motor, Pinion and Bearing from Top Drive. Check Gear Box tolerances and all components within for any issues.;Start installing new Rineer motor.
Wire tie all bolts, Function test. Good. Layout Halliburton 6-3/4" BHA components on drillers side catwalk racks.;PJSM, P/U and M/U BHA #5, 6-3/4" triple-combo,
Upload MWD, Shallow pulse test, Load sources, Continue M/U BHA T/ 325'. Submitted BOPE Test results to AOGCC and BLM @ 15:30.;Trouble Shoot top drive
rotation forward reverse.;RIH f/ 325' t/ 2600'.;Trouble shoot top drive rotation, spinning while in neutral, going forward while in reverse, change motor pot board x2,
check wires to ensure continuity, check swash plate on motor, # 2 is working correctly in all functions, #1 is not working correctly.;Hauled: 0 bbls Solids to KGF
G&I
Cumulative: 175 bbls
Hauled: 0 bbls Fluid to KGF G&I
Cumulative: 831 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/6/2023 Continue troubleshooting TDS HPU pump #1. Find the problem, repair and test. Good. Sylenoid valve for pump #1 on the TDS HPU.;Fill pipe and break
circulation. Make connection and ream down to find top of cement @ 2632' md. Drill through cement and wiper plugs and find Float Collar at 2655' md Drill down
and find Float Shoe at 2743' md Drill 20' of new formation T/ 2770'. Pump sweep and clean up well. P/U 70K S/O 61K.;Rig up testing equipment for FIT. Flood all
paths to be pumped and perform FIT T/ 13.15 ppg EMW. 11.5 gallons pumped and 10 gallons returned. Current MW @ 9.1ppg Casing Shoe @ 2743' MD 2529'
TVD. Pressure up to 533psi. R/D and blow down all test equipment, Choke line, Kill Line and Choke.;Drill 6-3/4" Production hole F/ 2770' T/ 3161', 278 gpm, SPP
1379 psi, 63 rpm, 4.2k tq on bottom, 1-3k WOB, Max Gas 512 units, MW 9.05ppg in and out, ECD 10.0 ppg, P/U 80K, S/O 64K, ROT 72K.;Drill 6 3/4'' Production
Hole F/ 3161' t/ 3548' 278 GPM 1437 psi SPP 60 RPM 4k tq on bottom, 2-4kl WOB Max Gas 248 units. MW 9 ppg ECD 9.9ppg 80k PUW 64k SOW 72k
ROT.;Drill Ahead 6 3/4'' Production Hole f/ 3548' t/ 3775' 278 gpm 1400 psi SPP 60 RPM 4.5k Tq on Bottom, 2k WOB, MW 9.1 ppg ECD 10.22 ppg, PUW 84k
SOW 65k ROT 78k Distance to Plan 3.91' 2.05' Low 3.33' Left.;CBU, Obtain Survey and SPR's, Flow Check Well Static, Blow Down Top Drive.;Make Wiper Trip
f/ 3775' t/ 2722', No Hole Issues.;Service rig and top Drive.;RIH f/ 2722' t/ 3775' No Issues Wash last stand to Bottom.;Hauled: 24 bbls Solids to KGF G&I
Cumulative: 199 bbls
Hauled: 56 bbls Fluid to KGF G&I
Cumulative: 887 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/7/2023 On bottom at 3775' and pumped a 20 bbl hi-vis nutplug sweep around with a 20% increase in cuttings with sweep back to surface (on time).;Resumed drilling
ahead 6 3/4" hole from 3775' to 4210'. Rot wob 3K, 286 gpm-1658 psi, 60 rpm-5700 ft/lbs on bott torque, 120 ft/hr ROP, MW 9.0/vis 63, ECD's at 10.2 ppg, BGG
79 units, max gas 541 units.;Cont drilling 6 3/4" hole from 4210' to 4624'. Rot wob 3K, 275 gpm-1595 psi, 80 rpm-5700 ft/lbs on bott torque, 120 ft/hr ROP. Sliding
wob 2K, 274 gpm-1585 psi, 159 psi diff, 160 ft/hr ROP. MW 9.0/vis 63, ECD's at 10.3 ppg, BGG 46 units, max gas 162 units.;Cont drilling 6 3/4" hole from 4624'
to4829' 275 gpm 1560 psi 80 rpm 7k tq on bottom, PUW 110k SOW 70k ROT 82k MW 9.05 ppg ECD 10.2 ppg top drive acting up while in rotation changing from
forwards to reverse on its own, Distance from plan 5.20' 5.19' Above .32' right.;Circulate bottoms up, Obtain surveys and SPR's, Flow check the well static, Blow
down the top drive.;Make wiper trip f/ 4829' t/ 2723' No hole issues.;Service rig and top drive, change oil in floor motor and grease crown.;Trouble shoot top drive
rotation, check 37 pin cable continuity from dog house to HPU, found it was bad multiple legs shorting, sent hands after new cable at warehouse, install end on
new cable and install cable to box.;Hauled: 40 bbls Solids to KGF G&I
Cumulative: 239 bbls
Hauled: 160 bbls Fluid to KGF G&I
Cumulative: 1047 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 277 lbs
3/8/2023 Cont installing new 37 pin cable from topdrive control panel in doghouse, down to HPU skid and hard wiring in at HPU. Allowed topdrive hydraulics to run and
warm up, then function tested topdrive on HPU pump #1 with no issues, then both pumps with no issue. Hole taking 1/2 bph on trip tank.;Eased out of surface
casing from 2723' and TIH slow to 3836', down wt 60K. MU topdrive and filled pipe, blew down topdrive, cont TIH from 3836' to 4768', down wt 68K. Filled pipe on
last stand, pumped 20 bbl hi-vis nutplug sweep and washed to bottom at 4829' with no issues.;Circulated sweep around at 268 gpm-1556 psi, 68 rpm-7100 ft/lbs
off bott torque. Had a 20% increase in cuttings at bottoms up, with a max of 239 units, then another 20% increase in cuttings with sweep to surface. Sweep back
on time.;Resumed drilling ahead from 4829' to 5260'. Rot wob 6-7K, 285 gpm-1860 psi, 80 rpm-7470 ft/lbs on bott torque, 100 to 120 ft/hr ROP. Sliding wob 2-3K,
283 gpm-1895 psi, 313 psi diff, 50-90 ft/hr ROP. MW 9.1/vis 65, ECD's at 10.5 ppg, BGG 41 units, max gas 114 units. No topdrive issues.;Cont drilling 6 3/4" hole
from 5260' to 5819' 283 gpm 1950 psi SPP 80 RPM 7700 tq on bottom PUW 125k SOW 75k ROT 86k 5-6k WOB 103 max gas Distance from Plan 4.23' 4.23'
Low .11' Left.;CBU, Obtain survey and SPR's Flow check well slight seepage.;Make Wiper trip f/ 5813' t/ 4766' 25k over pull seen f/ 5184' t/ 5075' No issues
getting sticky or hanging up.;Service rig and top drive, check and grease draw works, inspect breaks and weight indicator on deadman, Clean pump screens 90%
packed off.;RIH f/ 4766' t/ 5813' wash last stand to bottom, pump hi vis sweep around 2246 units of gas on bottoms up.;Drill Ahead 6 3/4'' Hole f/ 5813' t/ 5871'
283 gpm 2175 psi 80 rpm 7.5k tq on bottom 125k PUW 75k SOW 86k ROT.;Hauled: 40 bbls Solids to KGF G&I
Cumulative: 279 bbls
Hauled: 120 bbls Fluid to KGF G&I
Cumulative: 1167 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 6 lbs
Cumulative: 283 lbs
3/9/2023 Cont drilling 6 3/4" hole from 5871' to 6274'. Rot wob 3-4K, 284 gpm-2123 psi, 78 rpm-8000 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 4K, 286 gpm-2189
psi, 269 psi diff, 120 ft/hr ROP. MW 9.1/vis 66, ECD's at 11.0 ppg, BGG 49 units, max gas 181 units.;Cont drilling from 6274' to 6657'. Rot wob 6-8K, 286 gpm-
2201 psi, 80 rpm-8294 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5K, 282 gpm-2364 psi, 356 psi diff, 118 ft/hr ROP. MW 9.2/vis 61, ECD's 11.4, BGG 25
units, max gas 435 units. 33 units conn gas after connection at 6626'.;Cont drilling from 6657' to 6812' 286 gpm 2286 psi 80 rpm 9.6k tq on bottom 5-6k WOB
Max gas 301' increase MW t/ 9.2 ppg PUW 145k SOW 85k ROT 105k.;CBU, obtain survey and SPR's, Flow check well slight loss about 2'' in riser in 10 min,
Blow down top drive.;POOH f/ 6812' t/ 5798' no hole issues.;Service rig and top drive, clean suction screens.;RIH f/ 5798' t/ 6812' with no issues wash last stand
to bottom, Pump Hi vis sweep.;Drill 6 3/4'' Hole Section f/ 6812' t/ 7204' 286 gpm 2000 psi 80 rpm 10k tq on bottom MW 9.2 ppg ECD 11.07 PUW 150k SOW 90k
ROT 107k Distance to Plan 3.18' 1.46' Above 2.83' Left. Sweep Back on time 100% increase in cuttings 1954 units of gas on bottoms up after wiper trip.;Hauled:
50 bbls Solids to KGF G&I
Cumulative: 329 bbls
Hauled: 110 bbls Fluid to KGF G&I
Cumulative: 1277 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 283 lbs
3/10/2023 Cont drilling 6 3/4" hole from 7204' to TD at 7554' md/6355' tvd. Rot wob 3 to 8K, 288 gpm-2311 psi, 80 rpm-10,700 to 12,000 ft/lbs on bott torque, 120 ft/hr ROP.
MW 9.2+/vis 65. ECD's 11.1 ppg, BGG 24 units, max gas 389 units. Final survey projected at 7554' md, 29.60 Inc, 35.52 Azi. 6355' tvd;puts us 25.01' high and
12.53' left of the line. TD called early by Geo. Sent AOGCC notification of upcoming liner run and cementing.;CBU at 285 gpm-2132 psi, 80 rpm-9800 ft/lbs off
bott torque. After bottoms up obtained survey and SPR's, then pumped a 20 bbl hi-vis nutplug sweep around. Sweep back 5 bbls early with a 50% increase in
cuttings. 10 minute flow check= fluid dropped 2" in wellbore.;Pulled up hole on elevators, up wt 180K, from 7554' 5 stands and blew down topdrive. Cont pull up
hole on elevators to 5380', and had to work pipe at 6920', 5724', 5668', 5536' and 5392'. At 5380' could not work past on elevators. MU topdrive, established circ
and rotation.;Backreamed from 5380' staging up from 111 gpm-623 psi, 40 rpm-7800 ft/lbs to 290 gpm-2034 psi, 80 rpm-7614 ft/lbs. Backreamed to 4954'. Mostly
clay and super fine sand on shakers, no coal.;Cont back reaming from 4954' to 3529' PUll out of the hole on elevators f/ 3529' t/ 739' Flow check well at BHA, well
static.;Stand Back and L/D BHA, unload sources, download MWD, continue L/D BHA Bit graded a 3-1- in gauge, clean and clear rig floor.;Service rig and top
drive, grease crown, clean suction screens.;M/U Clean Out BHA RIH Bit Stab and Bit sub f/ surface t/ 2725'.;Hauled: 62 bbls Solids to KGF G&I
Cumulative: 391 bbls
Hauled: 273 bbls Fluid to KGF G&I
Cumulative: 1550 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 283 lbs
3/11/2023 Fill pipe at 2726', no issue exiting window, down wt 60K, TIH to 3728' and fill, TIH to 4709' and fill, TIH to 4838' and string taking weight.;MU topdrive, filled pipe,
washed and reamed down to 4898', then washed/reamed every fifth stand down to 5392'. Cold not trip on elevators, washed and reamed to 5767' at 250 gpm-664
psi, 50 rpm-6900 ft/lbs torque.;CBU at 254 gpm-684 psi staying above the coal at 5770'. Max gas at bottoms up was 79 units.;Attempt to TIH on elevators, could
not, cont to wash and ream down from 5767' to bottom at 7554'. 246 gpm-805 psi, 50 rpm-6900 to 11,000 ft/lbs. Max gas for entire trip 487 units with a mud
weight of 9.4 ppg.;Pump a 20 bbl hi-vis nut plug sweep around at 270 gpm-928 psi, 80 rpm-9765 to 10,163 ft/lbs off bottom torque. Sweep came back 2.3 bbls late
and a 75% increase in clay, sand and fine coal chips.;Flow check, POOH from 7554' to Surface No issues, Flow check at shoe and HWDP both static.;L/D BHA,
Jars collars and stab.;Clean and clear floor, R/U to run liner.;PJSM Run 4.5'' liner as per detail P/U and baker lock float equipment, Check floats (good), Continue
RIH installing centralizers and filling on the fly topping off every 10 jts, currently @ 1874'.;Hauled: 0 bbls Solids to KGF G&I
Cumulative: 391 bbls
Hauled: 0 bbls Fluid to KGF G&I
Cumulative: 1550 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 0 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 283 lbs
3/12/2023 Cont PU and single in hole with 4 1/2" 12.6# L-80 DWC/C-HT liner from 1874 to 2725. Torqued liner connections at 6150 ft/lbs.;MU XO and topdrive, CBU at 210
gpm-212 psi, max gas 24 units at bottoms up.;Cont PU single in hole from 2725' to 4950', down weight 50K, no issues. Ran a total of 122 joints.;MU XO and
topdrive eased into circulating and staged up to 172 gpm-281 psi, RD casing tongs, max gas 38 units at bottoms up, changed out elevators, held PJSM with Baker
Rep on PU liner hanger, shut down and broke off topdrive.;PU Baker HRD-E ZXP Flex Lock V production liner hanger assembly and MU on stump at 6100 ft/lbs
torque. S/O, mixed and poured xanplex, up wt 67K, dwn wt 54K. MU XO and 1st stand HWDP. MU topdrive and circulated one liner volume at 211 gpm-401 psi.
Broke off topdrive.;Cont ease in hole with liner string on 7 more stands HWDP, then 33 stands 4 1/2" DP to 7533' with no issues. MU stand 34 and topdrive, broke
circ at 112 gpm-474 psi, washed down and tagged bottom at 7558' twice with liner string. PU and parked 6' off bottom.;Cont circulating while spotting cement
units, staged rate up to 201 gpm-667 psi with a max of 87 units gas. Shut down pump, racked back stand 34, MU 15' pup, PU Baker cement head.;MU topdrive on
cement head, RU circ lines and valves to rig floor and cement head, cont to circulate at 209 gpm-766 psi, held PJSM with rig team and cementers. Max gas 197
units. MW 9.4 ppg.;Halliburton pumped 3 bbls water to flush lines, then 5 bbls to fill lines. Shut in at Baker cement head and PT lines at 725 psi low 4100 psi high.
Lined up Baker cement head to Halliburton, pumped 30 bbls 10.5 ppg spacer at 4.5 bpm - 665 psi, followed with 158 bbls (380 sx) 12 ppg Type I II Lead;cement at
4 bpm, 86 to 372 psi, followed with 19 bbls (98 sx) 15.3 ppg Type I II Tail cement at 4 bpm- 65 psi. Baker released dart, Halliburton then displaced with 9.4 ppg
6% KCL mud at 4 bpm- 88 to 1325 psi. 30 bbls into displacement saw dart latch wiper plug. With 80 bbls to go, reduced rate to 3;bpm- 1200 psi and bumped
plug/landing collar 104 bbls into displacement (calculated at 107 bbls). FCP 1325 psi. Halliburton increased to and held 1980 psi ( 1655 over fcp) for 1 minute.
Slacked off on blocks, anchor holding. Increased pressure to 2525 psi and held 5 minutes. Slacked off on blocks;from 68K to 25K, giving us a good indication
hanger was set. CIP at 22:38 on 3-12-23. No losses throughout the job. Increased pressure to 3880 psi and held 1 minute to shift HRD-E and release run tool.
Saw slight bobble on weight indicator. Bled back 1.5 bbls to truck and floats held. PUW 40 K;run tool released. RD cement hose, LD Baker cement head, MU
topdrive. PU 6 to clear dogs from hanger top, slacked off from 40K to 20K (20K applied) on liner top and saw a good indication on weight indicator packer set. PU
and rotated at 20 rpm, 3400 ft/lbs torque, S/O and set down to 20K;(20K applied) one time, to ensure weight transfer to set packer. Top of liner hanger at 2569,
top of landing collar at 7466. Pressured up to 500 psi on drill string and PU slowly. Once psi started dropping, rig started pumping and did one full circ at 410gpm-
200 psi. Had 30 bbls of spacer and 50;bbls of cement to surface. Shut down pump, LD 15 pup jnt, MU topdrive and pumped second circulation at 410 gpm-200
psi. RD and released Halliburton crew.;POOH w/ Running tools f/ 2553' t/ Surface, break down running tool and L/D.;Clean and clear floor, M/U stack washer and
flush stack and function all BOP components, L/D stack washer, P/U and break down cement head and L/D.;M/U polish Mill Assembly and RIH t/ 2444' adjust
torque on top drive.;Hauled: 4 bbls Solids to KGF G&I
Cumulative: 395 bbls
Hauled: 276 bbls Fluid to KGF G&I
Cumulative: 1826 bbls
Hauled: 50 bbl Cement to KGF G&I
Cumulative: 50 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
3/13/2023 Cont ease in hole with Baker 5.68" TBR dress and polish mill from 2444' to 2507'. MU topdrive and circ at 168 gpm-163 psi, wash down and tag liner top at
2569.53'. Up wt 52K, dwn wt 50K. PU 10', rotate at 20 rpm-2875 ft/lbs, S/O and dress liner top as per Baker Rep.;PU 6', lined up on spacer, pumped 20 bbl hi-vis
spacer, followed with 148 bbls inhibited fresh water at 275 gpm-193 psi, 42 rpm-2542 ft/lbs torque, kept dress off mill 1' off liner top. With good inhibited water to
surface shut down and blew down topdrive.;Pull string 10' up hole and monitored for flow while cleaning up shakers and trip tank. Staged pipe tub for DP, CCI set
up to vac wiper balls on pipe rack. No flow, no loss, well static.;POOH LD 4 1/2" DP from 2584' to surface. LD Baker polish mill, good indication of dress off mill to
liner top contact.;Serviced rig and topdrive.;Replace rollers on iron roughneck.;Function test IR. MU 4 1/2" mule shoe and TIH from derrick to 1980'. MU topdrive
and flushed through pipe for 5 minutes at 238 gpm-118 psi, blew down topdrive, POOH LD 4 1/2" DP from 1980' to surface. RIH next batch of DP to 1944', POOH
LD same. RIH next batch from derrick to 1003', POOH LD same.;Closed blinds, RU test equipment. Flooded kill line and choke manifold. Pumped 2.10 bbls to
achieve 3000 psi and test 7 5/8" x 4 1/2" liner lap and liner for 30 min on chart. Good test, bled back 1.5 bbls. RD test equipment.;Pull wear ring, R/U Parker
casing equipment to run 4 1/2" tie back string.;MU Baker 5 3/4" bullet seal assembly on 1st jnt, ran 4.5'' Tie Back, Spaced out and M/U circulating equipment.
PUW 40k SOW 40K.;Circulate and mix 3% KCL into system.;R/D circulating equipment, blow down top drive, L/D one full jt and M/U 10' and 4' space out pups,
hanger and landing jt, land tubing on hanger, RILD's.;Hauled: 0 bbls Solids to KGF G&I
Cumulative: 395 bbls
Hauled: 650 bbls Fluid to KGF G&I
Cumulative: 2476 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 50 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 283 lbs
3/14/2023 Landed hanger, down wt 40K, vacd out cellar box and RILDs. Removed and LD landing joint.;Flooded stack and kill line. RU test equipment, purged air for testing.
Performed MIT-T at 3000 psi for 30 min on chart, pumped 1.2 bbls, good test, bled back 1.2 bbls. RU on annulus and performed MIT-IA at 2500 psi for 30 min on
chart, pumped 0.8 bbls, good test, bled back 0.8 bbls. RD test equip.;Flushed surface equipment and lines with Baraklean solution followed with inhibited solution.
Blew everything down and set 2 way check in hanger. Installed shipping beams, loaded trailers with mud product, RD Sperry shack , shipped Sperry tools to
Paxton, vac'd out stack and opened ram doors.;pressure washed and inspected cavities, buttoned up ram doors.;ND flowline and riser, ND stack, worked dry hole
tree into cellar, verified orientation of master valve with Production Rep, installed tree and torqued bolts, cont cleaning tank bottoms, shipped load of Sperry tools
to town, topped off tree with diesel, tested hanger void, neck seals and tree at;5000 psi each for 15 min each, good tests, pulled 2 way check, topped off with
diesel, installed tree cap, closed master.;RD topdrive, clear rig floor of hand tools, and XO/subs, R/D Kelly hose & service loop. R/U TDS and installed in cradle.
R/U L/D slings, lowered TDS to catwalk. Removed T-bar, prepped to scope mast. Scoped mast, hung off blocks. Finished cleaning in pits. cleaned out bear traps
on MP's. R/D kill;on mezz deck. R/D and hauled off hurricane vac to staging pad.;Crew change, held PTSM. Prepped rig floor for unspooling drill line. Unspooled
drill line, cut 25 wraps = 119' of drill line. R/D centrifuge and installed shipping blocks. R/D iron roughneck, installed shipping beams. Removed torque tube
turnbuckles, secured Kelley hose and service loop to mast. R/D;TD HYD lines on rig floor, gen # 3, and remove mast HYD cylinder covers. R/D catwalk, laid over
beaver slide and MGS. R/D and unplugged MWD & Geo-Log shack. Staged BOP cradle next to catwalk. Final report for SRU 231-33, released rig @ 06:00 hrs.
Moving to Paxton 12 AFE.;Hauled: 8 bbls Solids to KGF G&I
Cumulative: 403 bbls
Hauled: 312 bbls Fluid to KGF G&I
Cumulative: 2788 bbls
Hauled: 0 bbl Cement to KGF G&I
Cumulative: 50 bbl
Lost: 0 bbl Fluid Down Hole
Cumulative: 0 bbl
Daily Metal: 0 lbs
Cumulative: 283 lbs
Activity Date Ops Summary
3/20/2023 Fox Energy coil package and Cruz crane depart N. Kenai.,PTW, JSA with crew. Spot in coil unit, step deck aux trailer, N2 pump, Cruz 100 ton crane, and 2ea
rain for rent fluid tanks with secondary spill guard berms.,As per sundry, pressure test BOPE 250 psi low, 3000 psi high. AOGCC BOP witness waived by Jim
Regg.,Rig down testing equipment. Install night cap on BOPE stack. Stab 1.75" CT through injector head and dress pipe. Location walk around completed.
SDFN.
3/21/2023 PTW, JSA with Fox Energy coil crew, Cruz construction crane operator, Yellow Jacket thru tubing tool hand, and Hilcorp production lead. Emphasis on attention
to road conditions and driving habits, proper containment under equipment and spill prevention procedures with crew.,PU injector head, stab lubricator and make
up Yellow jacket oilfield services milling BHA. Pull test coil connector to 25K. Pressure test MHA to 4000 psi. BHA: Ext CTC, DFCV, Bi-Di-jar ,TJ Hyd disco,
Circ sub, Mud motor, x over, Tri-cone rock bit. BHA OD 2.88" with 3.75" roller cone rock bit. OAL = 26.37'. Stab on well. Circulate to return tank. Confirm
motor spinning. Pressure test lubricator 250/3000.,RIH for dry tag. Tag @ 7417' CTMD with 3K down. PU clean. Online with produced water to establish initial
circulating parameters. 1.3 BPM @ 2450 psi circulating pressure.,Start milling at 7417' CTMD. No weight stack with 200 psi motor work. Good ROP from 7417'
CTMD to 7475' CTMD. Started stacking 2k down at 7475' CTMD. Minimal motor work down to 7477.5' CTMD. 8K weight stack and hard stall of motor at
7477.5' CTMD indicating mill has engaged rubber wiper plug. PU to repeat stack and stall on wiper plug rubber.,78 bbls circluated when max depth of 7477.5'
CTMD achieved. Zero stroke counter. Start circulating out 9.2 ppg mud with 8.4 ppg produced water (114 bbls required). POOH chasing bottoms up to
surface. Tagged up. Close upper master and swab valve. 228 bbls of 8.4 ppg produced water circulated during coil intervention.,Lay down YJOS milling BHA.
Leave coil connector, DFCV, and install 2.375" PAC x 3/4" ported sucker rod X over. Stab on well. Blow down CT reel with N2. 23 bbls (reel volume)
recovered. Rig back CTU injector head. Perform location walk around. SDFN.
3/22/2023 PTW, JSA with crew. Pick injector head and stab lubricator. Make up Halliburton CBL logging tools. Stab on well. PT stack 250/3000 psi.,Stop at 7475' CTMD
and wait for tool to turn on.,Log OOH with CBL at 40' per minute to liner top packer at 2570'. Station stop for 5 minutes. Continue logging OOH to surface at 60
fpm.,Lay down HES logging BHA and download data. Pull depth/time file from Fox CTU acquisition system. Send log to town to confirm depth correlation to
proposed perforation depth intervals. Transfer liquid N2 from transport to N2 pump. CBL log accepted by town engineer. Make up ball drop nozzle (no check
valves).,RIH to perform N2 blow down. Cool down N2. PT N2 lines 250/4000 psi. Online down coil with N2 @ 800 scf/min taking returns from CTx tbg annuli.
Tag PBTD @ 7482' CTMD. Pick up 2'. Increase N2 rate to 1200 scf/min.,Parked at 7478' CTMD while monitoring return tank. Initial fluid slug returned from
wellbore of 106 bbls with 200K of nitrogen pumped. Swap valves to reverse out remaining wellbore fluids. 2250 psi circ pressure broke over indicating remaining
fluid moving up coil. 15 additional bbls unloaded during reverse out. Calculated returns 114 bbls. Return tank strap showing 121 bbls. 99% N2 at return
tank.,Shut down N2 pump. POOH while taking returns up coil to bleed off N2 pressure. Total N2 pumped during CT intervention 231,082 scf. Total fluid
returned per return tank strap 121 bbls. Tagged up at suface. Close upper master and swab valve. SITP 0 psi.,Rig down CTU and auxiliary equipment.
Location walk around complete. SDFN. Fox de-mobe N2 pump for N2 bullhead job on CLU-10RD. '
Plan forward: Production to use lease gas to increase wellbore pressure `1500-2000 psi to prep for perforating.
3/27/2023 YJ Eline on location. Check in at the office and open PTW & PJSM. Drive to well & spot in equipment. Begin rig up. Pick up lubricator & GPT toolstring. Begin
pressure test, had leaking oring while pressuring up. Attempt to blow out fluid with air from unit, methanol spill out of unthreaded connection. Fix oring and PT to
250/3000, pass.,RIH w/ 7' x 2" WB, 7' x 2 3/4" GPT tool, w/ CCL (7' CCL to bottom of tool). Did not find fluid while RIH. Tag TD @ 7467'. Log from TD to 7000' &
POOH.,WHP = 1754. RIH w/ GR/CCL, shock sub & 24' x 2 7/8" Geo Razor XDP guns (6 spf). CCL to top shot = 9.5'. Tag TD @ 7466'. Pull correlation pass, send
to geo, on depth.
Shoot the Ty_62-5 sand from 7437' - 7461'. CCL stop depth = 7427.5'.
Initial pressure = 1739 psi, 5 min = 1780 psi, 10 min = 1802 psi, 15 min = 1827 psi.
POOH. Bull plug filled w/ sand.
Bump up pressure = 1894 psi.,Lay down toolstring and lubricator. RDMO eline unit and crane.
3/29/2023 AK Eline MIRU, PJSM, PTW with operations
PT equipment to 1175 psi,
RU GPT w/ GR/CCL,RIH with GPT @ 120 fpm. Found fluid level at 3460' with tubing pressure at 1175 psi. Tie-in log. Tagged bottom at 7,409'.
POOH logging, confirmed fluid @ 3460'.,Rig down and move to 224-10. Close out ticket on 231-33.
3/30/2023 On Location, TGSM/JSA/Permit with ops and company rep
RU W/L & PT lubricator to 250/2500 psi - Good,RIH w/ 3.5" x 7' DD bailer to 3,458KB (found fluid level), tag at 7402' WLM, work tools to 7412'. POOH w/ flapper
open, empty bailer.
RIH w/ Same to 7412' WLM work tools to 7420', POOH, full of mud.
Repeat 4 more runs to 7439' with bailers of sand,Pressure up tubing to 2500 PSI, fluid level still at 3,468' (no movement), tag at 7420' WLM.
Bled pressure to 1500 PSI, Bailed to 7422' WLM 1 cup of sand
RIH with 3.72" GR to 7421 WLM.,SDFN, Secure well.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
SRF SRU 231-33
Swanson River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00028 SRU 231-33 Completion
Spud Date:
3/31/2023 TGSM/JSA/Permit
RU Wireline, PT Lubricator 250/2500 PSI - Good, Bleed well to 1200 PSI,Bail fill from 7422-7432'.
Rig Back for EL tag
YJ Eline RU PT 2500/250 PSI
RIH with GR/CCL and GR and tag @ 7419' KB
RD Eline,SL RIH w/ 3.72" GR to 7,426' and work tool to 7430' POOH
Rig Down WL - Secure well.
4/1/2023 TGSM/JSA/PTW
Rehead - check tool string, PT Lub 250/2500 PSI Good
Bail sand from 7426 to 7456 with 2.5" DD Bailer. Using spears and 2" bailer as needed.
RD W/L - Secure well.
4/2/2023 TGSM/JSA/PTW. RU Wireline - PT Lubricator 25/2500 PSI - Good
Bail from 7436-7453'
Run 3.72" GR to 7444' work to 7450'
RIH w/ 3.9" BL brush to 7448 to 7450' POOH
Pressure well to 2500 PSI
RIH w 3.9" brush to 7444'
RDMO well
4/3/2023 Yellow Jacket E-line arrive on location. Hold TBT and approve PTW.
MIRU and Pressure test lubricator to 4000 psi.,RIH with 3.62" gauge ring. GR/CCL to bottom of gauge ring = 11.0'.
Tubing pressure = 2550 psi.
Find fluid level at 3095'.
Tag at 7429'. Corrected to Yellow Jacket GPT log dated 3/27/23.,Fox N2 arrive on location. Hold TBT and have them sign onto PTW.
MIRU N2 equipment. Cool down pump and PT lines to 4000 psi.,Pump N2 at 1200 scf/min down tubing. Pressure up tubing to 4000 psi.
Log with GPT after tubing pressure up to 4000 psi. Fluid is still at same depth of 3095'.
RIH and re-tag with 4000 psi, tag depth is 1' shallower now at 7428'.
POOH and confirm fluid depth still at 3095'.,Discuss with town engineer. Decide to rig down E-line and wait on coil cleanout.
RDMO E-line and N2 pump truck.
4/4/2023 Fox coil arrive on location. Hold TBT and approve PTW.
MIRU coiled equipment. Use Cruz crane for lifts.
Move and spot Rain for Rent tanks with spill containment underneath.,NU BOP's on tree. Run hardline from flow cross to choke skid. Run high pressure hose
from choke skid to return tank.
Load supply tank with produced water and add friction reducer to vac truck on each load.
Change out coil stripper.,Test coil BOPE to 250 psi low / 3000 psi high. Good test.
Jim Regg with AOGCC waived witness via email at 15:52 on 4/3/23.,Secure well with night cap on top of BOPs. Close blind/shears.
Finish running hardline from Yellow Jacket tri-plex pump to coil reel.
SDFN.
4/5/2023 Fox coil arrive at Swanson office. Hold TBT and approve PTW.
Warm up equipment. Pick up injector and lubricator. MU coil roll-on connector, DFCV's, 2-1/8" stingers (x2), 2-1/8" wash nozzle.
Stab onto well and PT 250/3000 psi.,Open well and RIH. Online with pump and fluid pack well out to return tan.
Dry tag at 7444' ctmd. PU to 7400' and bring pump on-line. Establish 1:1 returns with pump rate = 2.2 bpm and CTP = 3950 psi.,Jet through fill from 7444' to
7480' ctmd. Stay on bottom and pump 50 bbls before chasing returns up hole.
POOH at 75 ft/min chasing returns pumping 2.2 bpm. Still getting 1:1 returns. See sand in returns at surface.
Pump until coil is at surface. Shut down fluid pump and close in swab.,Cool down N2 pump and blow down coil reel with N2 out to return tank.
Break off cleanout BHA and set down lubricator and injector.,Yellow Jacket arrive on location. Conduct TBT and approve PTW.
MU 3.5" CIBP toolstring and lubricator on top of coil BOP's. GR/CCL to top of plug = 12.0'. PT lubricator and RIH.
Send plug correlation log to RE/GEO. Confirm on depth.
Set top of plug at 7427'.,RDMO wireline equipment.
Secure well with night cap on top of coil BOP's.
SDFN.
4/6/2023 Fox coil arrive at Swanson office. Hold TBT and approve PTW.
Warm up equipment. Pick up injector & lubricator. MU 2-1/8" stingers (x2) and reverse out nozzle.,RIH lined up through choke to reverse circulate.
Online with N2 pump at 800 scfm with coil depth = 1500'.
Get fluid at tank with coil at 2400' and pumping 1000 scfm, wellhead pressure = 1330 psi.,RIH and tag plug at 7444' ctmd. Pick up coil to 7442' ctmd and continue
pumping N2 down backside, taking returns up coil.
N2 rate = 1200 scfm, whp = 2250 psi.,Recover all 113 bbls of fluid from wellbore back to return tank. Max wellhead pressure = 2500 psi at 1400 scfm.
Pumped total of 163,800 scf of N2.,Offline with N2 pump and POOH. Bleed WHP to 0 psi while POOH.
Coil at surface, shut-in swab. WHP = 0 psi.,RDMO coiled tubing equipment.
4/7/2023 Yellow Jacket E-line arrive at Swanson office. Hold TBT and approve PTW.
Warm up and spot equipment. MU GPT toolstring. GR/CCL to bottom of GPT = 7.0'.
Slobber line is frozen or has thick grease, need to warm hose to get fluid passing.,PT lubricator to 250 psi low / 4000 psi high.
Open well and RIH. Tubing pressure = 1750 psi.
Tag plug with GPT at 7427'. Did not find fluid above plug.
POOH.,MU and RIH with 2-7/8" x 14' perf gun. GR/CCL to top shot = 9.5'
Send correlation data to RE/GEO. Confirm on depth.
Perforate 7412-7426' (TY 62-5 sand).
Initial pressure = 1735 psi
5 minute = 1749 psi
10 minute = 1758 psi
15 minute = 1773 psi
POOH. Bull plug on gun is damp with a little sand.,Flow well at 500 mscfd. Initial starting tubing pressure = 1970 psi.
Run GPT across perfs with well flowing. Fluid level = 7110', no significant cooling across perfs. Tag at 7425'.,Continue to let well flow, remain in well with GPT.
Run 2nd GPT with well flowing. Fluid level = 6945', no significant cooling across perfs. Tag at 7425',POOH. RDMO Yellow Jacket E-line equipment.
4/14/2023 Yellow Jacket EL crew arrive at SRF office, sign in, hold PJSM and obtain PTW. Discuss scope of work and mobilize equipment to location.,SITP - 2480 psi
Spot equipment, RU and MU weight bar, GPT, #10 setting tool and 3.50" OD CIBP. (14' CCL to plug)
PU lubricator/tools and move to wellhead. PT 250/4000 psi,Open swab and RIH w/ GPT logging survey. Locate fluid level at 5865'. (936' above proposed TY-56-9
perfs at 6801'-6832')
Call out Fox Energy for N2 pumping unit.,W/O N2 unit arrival. (EL tools in hole standing by at 5600'),Fox N2 arrives. Add service to PTW, hold JSA and RU hard
line to wellhead. PT lines 250/4000psi.
Start cool down, open wing valve and roll on pump at 1200 scfm. Build pressure to 3500 psi (52,096 scf). SD pump. Wait 30 minutes, run GPT to locate fluid level.
(50 psi decrease and 5' fluid drop).,Roll on N2 pump at 1200 scf and build pressure to 4000 psi (21,364 scf). SD pump. Pressure begins to drop (300 psi - 1/2 hr.).
RIH and locate FL at 6300'. Monitor FL to 6400'.,SITP-3450 psi. Kick on pump and build to 4000 psi. SD pump (26,829 scf). Log pass - FL at 6815'. RIH to 7400'
and run correlation pass for plug set.
Send log to town. Tie-in pass approved. Locate last FL at 7200'. Set CIBP at 7362'. POOH.
Release Fox N2.,OOH. Close swab (3450 psi). LD tools and lubricator, secure well.
4/17/2023 YJ E-line arrive at office, sign in, hold PJSM and obtain PTW. Travel to location.,Well bled down to 2000 psi.
Complete RU. MU 35' x 3" OD cement dump bailer and CCL. PU bailer, mix and fill with10 gallons of 15.8# cement. Stab on well and PT 250/4000psi. Pass,Open
swab and RIH. Lightly tagged CIBP at 7362', PU 15' and dumped cement. POOH.
OOH. Mix 10 gal.cement and fill bailer, RIH to 7325' and dump cement. POOH.
Estimated top of cement at 7327'.,OOH. MU 2-7/8" OD x 31' gun (6spf/60D) GeoDynamics perforating gun and GR/CCL (10' CCL to top shot).
RIH and begin bleeding well down to blow down tank to1500 psi. Run correlation pass and send to RE/GEO. Adjust correlation (add 2').
Pull into position at 6791' (CCL depth) and shoot the TY_56-9 (6801'-6832'). POOH.
Initial: 1538 psi 5 min: 1603 psi 10 min.: 1610 psi 15 min.: 1620 psi,OOH. Lower half of perf gun packed with sand. Rig back e-line and proceed to
flowback at 400 mcfd.
Pressure dropped to 600 psi after 2 hrs at 400 mcfd.,Open well to 1.0 mmcfd and continue to draw down. E-line MU GPT and RIH. SSV shut in on flow line 0 rate
/ 567 psi. Continue RIH w/ GPT.
Stop at 4000' due to tool weight loss. Pull uphole 200' with high tension weight on wire. Discovered top sheave and wireline twisted causing overpull. Corrected
torqued line but high stranded from overpull. POOH.,OOH. Discussed timeline to repair wire and continue log survey and decided to abort e-line operations.
RDMO.
Opened flow line wide open and well bled to header pressure (117 psi) in 1/2 hour.
4/25/2023 Travel from Yellow Jacket shop to Swanson River.,PJSM and permits.,Travel to location.,Rig up YJ E-Line.,Pressure test surface equipment 250/3500 PSI. Test
good. SI tubing PSI 2170. Pad Op opened 2500 PSI supply injection gas down tubing to push any fluid back in perfs. Well did not build over 2240 PSI so appears
to be injecting in to perfs.,Run in hole with GPT and Junk Basket w/ 3.625" gauge ring. Sat down at 2650'. Was able to work through. Continue down hole. Drifted
to existing perfs at 6853'. No fluid level detected. POOH.,OOH. Lay down GPT and Junk Basket. Make up CIBP & setting tool.,Run in hole with 4-1/2" CIBP (3.50"
OD). Tie in. Target depth 6751'. CCL to top of CIBP = 19'. CCL setting depth to be 6732' + 19'=6751'. Sent tie in log to town for approval.,Tie in approved. Spotted
CIBP on depth. Fired setting tool. Good weight drop indicating set. POOH.,OOH. Lay down setting tool. Make up dump bailer. Pad Op bleeding tubing down from
2200 to 300 PSI.,Run in hole with 3.00" x 35' dump bailer carrying 23 gallons of cement = 17.5' of cement depth. Sat down high at 6579' (Correlated depth). Work
tools 20 minutes. Could not get lower. POOH.,OOH. Cement had dump out of bailer while trying to work past 6579' obstruction. Consult Engineer.,Run in hole
with 1-11/16" tool string - 1-11/16" Junk Basket with 2.75" Gauge Ring. Sat down on obstruction 3 times at 6579'. POOH,Run in hole with 1-11/16" tool string - 1-
11/16" Junk Basket with 3.625" Gauge Ring to ensure no cement stringers above obstruction. Sat down on obstruction 3 times at 6579'. POOH,Laid down
equipment and secured well. Pad Op to place 2100 PSI on tubing. Request has been put in to State regarding more cement at obstruction point (6579') or
possibly a 2nd CIBP then additional cement..
4/26/2023 Travel from Yellow Jacket shop to Swanson River.,PJSM and permits.,Travel to location.,Rig up YJ E-Line.,Run in hole w/ 4-1/2 CIBP (3.50" OD). Target set
depth is 6569'. CCL to top of CIBP = 20.5'. Target depth for CCL is 6548.5' to = 6569'. Send log to town for approval. Town approved log.,Spot CIBP on depth.
Fire setting tool. Good weight loss. POOH.,OOH. Lay down setting tool. Make up dump bailer and cement. We will be making a total of 3 Dump Bailer runs using
3" x 25' bailer carrying 8 gallons of cement per run. Cement volume will give us 11.6' depth per run for total of 35' cement plug desired on top of CIBP.,Run in hole
w/ Dump Bailer #1. Tag CIBP at 6569'. Pick up 12' to 6557'. Fire bailer. Allow time for bailer to empty. POOH,Reload Dump Bailer.,Run in hole w/ Dump Bailer #2.
Stop 12' to above last dump 6545'. Fire bailer. Allow time for bailer to empty. POOH,Reload Dump Bailer.,Run in hole w/ Dump Bailer #3. Stop 12' to above last
dump 6533'. Fire bailer. Allow time for bailer to empty. POOH,OOH. Good fire on bailer. Laid Dump Bailer down. Pick up Gun #1 perf gun.,Run in hole with 3' x 2-
7/8" Carrier Perf Gun #1 for Zone 52-9 target 6370' to 6373'. TS to to CCL = 16.5'. CCL depth for perf 6353.5',Tie in pass. Send log to town for approval. Town
approved.,Pad Op bleeding tubing down from 2200 to 1300 PSI,Fire Gun #1. POOH. Monitor tubing pressure. No change from 1300 PSI in 15 minutes.,OOH.
Laid down equipment and secure well. End cap of perf gun dry.,Return to shop. Plan forward to continue perforating Beluga Zones.
4/27/2023 Travel from Yellow Jacket shop to Swanson River.,PJSM and permits.,Travel to location.,Rig up YJ E-Line.,Run in hole with GPT and 2-3/4" x 5' Carrier Perf Gun
#2. Found fluid level at 5755'. 560' of fluid on top of targeted perf depth. Tagged fill at 6366'. Top of first perf from Gun #1 was at 6370'.,Made tie in pass.
Engineers discussed options and then approved tie in log and to proceed to shoot.,Spot Gun #2. Target depth 6315' to 6320' at Beluga Zone 52-9. CCL to TS
19.5' = 6295' CCL depth for TS to be at 6315'. Fire Gun #2. GPT showing short spike in temp then back to normal with PSI on steady increase. Log up hole to
5500' (Fluid level not detected w/ PSI build) & stand by. Surface Pressure: Start 1200 - 5 Min 1400 - 10 Min 1500 - 15 Min 1550 - 20 Min 1650 - 25 Min 1725 - 30
Min 1750.,Log back down. Gassy fluid level detected 5800'. Bring well on production at 500MCF / 1750 PSI. Holding steady.,Well still on line. Go back down hole
& tag fill at first perf set at 6361' (5' Higher).Decision made to set WRP between first perf set 6370' - 6373' and 2nd perf set just fired at 6315' to 6320'. Call shop
for delivery of WRP & setting tool.,POOH.,WRP arrives. Set up running tool.,Run in hole w/ WRP 2-3/4" GG, 2-3/4" SS, 7' 2-3/4" WB setting tool w/ 4-1/2" WRP
22' CCL to plug, Set plug at 6353'. CCL depth 6331'. Found fluid at 5720'. POOH.,Rig down YJ E-Line. Production put well on line.,Mob YJ equipment back to
shop.
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9# @F 9# @
@
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.03.13 12:26:14 -08'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.03.13 13:29:44 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
63
Yes X No X Yes No 10
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Float Shoe 8 5/8
Rotate Csg Recip Csg Ft. Min. PPG9.05
Shoe @ 2742 FC @ Top of Liner2,655.00
Floats Held
6% KCL Polymer Mud
CASING RECORD
County State Alaska Supv.J Murphy / J Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.SRF SRU 231-33 Date Run 2-Mar-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Frontier 1.77 2,742.65 2,740.79
Csg Wt. On Hook: Type Float Collar:Frontier No. Hrs to Run:8
96
100
535
FI
R
S
T
S
T
A
G
E
10.5Tuned prime 60
120.2/123
1125
Trace
Halliburton
15.8 36
Bump press
Visual
Bump Plug?
21:10 3/2/2023 0
2,742.562,750.00
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL polymer
12 139
Type of Shoe:Frontier Casing Crew:Parker
www.wellez.net WellEz Information Management LLC ver_04818br
4
7 5/8 Casing Jts 7 5/8 29.7 L-80 BTC 83.49 2,740.79 2,657.30
Float Collar 8 5/8 BTC Frontier 1.61 2,657.30 2,655.69
7 5/8'' Casing Jts 7 5/8 29.7 L-80 BTC 2,630.73 2,655.69 24.96
7 5/8'' Pup Jt 7 5/8 29.7 L-80 BTC 3.15 24.96 21.81
Hanger/Packoff 16 BTC 1.61 21.81 20.20
l-ll 320 2.44
l-ll 175 1.16
6
TD Shoe Depth: PBTD:
Jts.
1
2
33
1
11
1
74
Yes X No X Yes No 10
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?:X Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
I II 380 2.39
I II 98 1.24
4
5,603.81
Liner 4 1/2 12.6 L-80 DWC/C-HT 3,000.93 5,603.81 2,602.88
6,091.18 5,644.42
RA Marker 4 1/2 12.6 L-80 DWC/C-HT 40.61 5,644.42
40.65 6,131.83 6,091.18
Liner 4 1/2 12.6 L-80 DWC/C-HT 446.76
RA Marker 4 1/2 12.6 L-80 DWC/C-HT
7,466.40
Liner 4 1/2 12.6 L-80 DWC/C-HT 1,334.57 7,466.40 6,131.83
7,509.18 7,467.50
Landing Collar 5 BTC JHobbs 1.10 7,467.50
1.27 7,510.45 7,509.18
Liner 5 12.6 L-80 BTC 41.68
Float Collar 5 BTC Frontier
Every joint first 46 joints, then every other joint last 74 joints.
Liner 4 1/2 12.6 L-80 BTC 41.45 7,551.90 7,510.45
Baker Flex Lock V
www.wellez.net WellEz Information Management LLC ver_04818br
4
Type of Shoe:Frontier Bullnose Casing Crew:Parker
12 158
7,553.207,554.00 7,466.40
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL Mud
22:28 3/12/2023 2570'
15.3 19
Bump press
CBL / TOL / Cement Returns during job
Bump Plug?
104/107
1980
50
Halliburton
FI
R
S
T
S
T
A
G
E
10.5 30
9.4 4
100
1325
Csg Wt. On Hook:116,210 Type Float Collar:Frontier No. Hrs to Run:16
6 5/8 BTC Baker
BTC Frontier 1.30 7,553.20 7,551.90
33.35 2,602.88 2,569.53
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.SRF SRU 231-33 Date Run 12-Mar-23
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
7,509.00
Floats Held3000
6% KCL Polymer Mu
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 7553 FC @ Top of Liner 2569
Casing (Or Liner) Detail
Float Shoe
Liner Hanger
5
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 Ops
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?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
7,554 N/A
Casing Collapse
Structural
Conductor
Surface 1,510psi
Intermediate 4,790psi
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Yes / Email Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Chad Helgeson
Contact Email:chelgeson@hilcorp.com
Contact Phone:(907) 777-8405
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:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
6,355 6,188 ~1,793
22"28
MD
28 28
Length Size TVD
988
2,529 6,880psi
3,070psi
PRESENT WELL CONDITION SUMMARY
7,362'7,362
Swanson River
Burst
4,984 4-1/2"8,430psi6,3557,554
7-5/8"2,743
11-3/4"988 988
2,743
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
A028399
223-008
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-133-10163-01-00
Hilcorp Alaska, LLC
Swanson River Unit (SRU) 231-33
Tyonek Gas Tyonek Gas, Beluga Gas
CO 716A
Proposed Pools:
Bryan McLellan
4/24/2023
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
12.6 / L-80 2,570
4/25/2023
Liner Top Pkr & N/A 2,570 (MD) 2,404 (TVD) & N/A
N/A N/A 4-1/2"
Perforation Depth MD (ft):
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:
AOGCC USE ONLY
Operations Manager
66
t
m
n
P
s
s
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
323-252
By Kayla Junke at 10:11 am, Apr 25, 2023
Digitally signed by Noel Nocas
(4361)
DN: cn=Noel Nocas (4361),
ou=Users
Date: 2023.04.24 16:53:37 -08'00'
Noel Nocas
(4361)
DSR-4/26/23BJM 4/27/23
10-407
Perforate New Pool P
SFD 4/25/2023
Beluga Gas
JLC 4/28/2023
4/28/2023
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.04.28 10:23:36
-08'00'
RBDMS JSB 050123
Well Work Prognosis Rev 1
Well Name: Swanson River 231-33 API Number: 50-133-10163-01-00
Current Status: Gas Producer Rig: Eline
Estimated Start Date: 4/25/23
Regulatory Contact: Donna Ambruz (8305) Permit to Drill Number: 223-008
First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (M)
Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M)
Maximum Expected BHP 2,325psi @ 5,325’ TVD Based on 8.4ppg gradient
Maximum Potential Surface Pressure: 1,793 psi @ 5,325’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4)
Brief Well Summary
Swanson River 231-33 is a sidetracked gas producer that was drilled and completed to 7,554ft in March
of 2023. The Tyonek intervals were completed and found wet.
The purpose of this sundry is to plugback the Tyonek Pool/PA and perforate the Beluga Gas Pool/PA.
Notes Regarding Wellbore Condition
x 4-1/2” mono-bore completion
x Liner/seal assembly @ 2,570’
Procedure:
1. Review all approved COAs
2. RU E-line, PT lubricator to 3500 psi High/250 psi Low
3. PU GPT and CIBP
4. RIH and confirm fluid depth is below 6,400’.
a. Use GL or N2 to pressure up and push fluid away into formation as necessary (3500 psi
limit)
5. Set CIBP at 6,751’, POOH
6. PU cement bailer and dump 35ft of cement on top of plug (min of 23 gal)
7. Bleed pressure to desired perforating pressure
8. Perforate Beluga sands and test as desired from reservoir engineer.
Interval Name MD Top MD BASE TVD Top TVD BASE FT
51-4 ±6,145’ ±6,215’ ±5,119’ ±5,183’ 70
51-7 ±6,223’ ±6,300’ ±5,189’ ±5,258’ 77
52-9 ±6,310’ ±6,374’ ±5,267’ ±5,325’ 64
Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist.
a. Record initial and 5/10/15 minute tubing pressures after firing
b. Above perfs will be shot in the Beluga Gas Pool governed by CO 716A
9. RD E-Line Unit and turn well over to production
10. Operations to flow well and test zones
11. Test SVS as per 20 AAC 25.265 once stable flow is achieved
a) Notify AOGCC 24hrs in advance of testing SVS
See attached email detailing change of scope and email approval granted. -bjm
perforate the Beluga
y CO 716A
plugback the Tyonek
Well Work Prognosis Rev 1
E-line Procedure (Contingency)
If any zone produces sand and/or water or needs isolated:
12. MIRU Eline and N2 pump truck
13. Pressure test equipment to 4,000 psi High/250 psi Low
14. Eline run PT to find fluid level
15. RU N2 or use gas lift and push fluid below perfs (verify fluid depth with PT tool)
16. PU 4-1/2” CIBP/WRBP or patch
a. If a plug is set (it must be set within 50ft of the top perf being plugged back)
b. For CIBP’s dump bail 35ft of cement on top of plug (unless there isn’t enough room to
the next perf)
c. Any CIBP with less than 35’ of cement will need approval from BLM prior to adding next
set of perfs
d. WRBP do not require approval from BLM before being set
If necessary to cleanout or unload well with coiled tubing,
17. MIRU Fox Coiled Tubing Unit, PT BOPE to 4,000 psi High/250 psi Low
18. Provide AOGCC 24hrs notice of BOP test
19. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth
20. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen
a. Reverse circ out any fluid if perfs are isolated/plugged back
21. RDMO coil tubing
Attachments:
1. Proposed Well Schematic
2. Wellhead Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
Updated by CAH 04-19-23
CURRENT SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status
TY_ 56-9 6,801’ 6,832’ 5,702’ 5,732’ 31’ 4/17/23 Open
TY_62-5 7,412’ 7,426’ 6,231’ 6,244’ 14’ 4/7/23 Open
TY_62-5 7,437’ 7,461’ 6,253’ 6,269’ 24’ 3/27/23 Isolated
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
22” Conductor Weld Surf 28’
11-3/4" Surf Csg/Conductor 47.0 J-55 8RD 11.000” Surf 988’(TOW)
7-5/8” Int Csg/Surf Csg 29.7 L-80 BTC 6.875” Surf 2,743’
4-1/2" Prod Csg 12.6 L-80 DWC/C-HT 3.958” 2,570’ 7,554’
4-1/2” Tieback 12.6 L-80 DWC/C-HT 3.958” Surface 2,569’
2
22”
11-3/4”
JEWELRY DETAIL
No. Depth ID OD Item
1 988’ N/A 12.25” Whipstock
2 2,570’ 4.875” 6.540” Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 7362’ CIBP 4/17/23 - w/ 35ft of cement
4 7,427’ 3.5” CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4” TOC @ Surface (Original 22-33)
7-5/8" TOC @ Surface (3/3/23)
4-1/2” TOC @ 2,561’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
RA Tags 5,605 & 6,092’
4
3
Updated by CAH 04-20-23
PROPOSED SCHEMATIC
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB = 18.17’
4” Type H BPV Profile
Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)FT Date Status
Bel_ 51-4 ±6,145’±6,215’±5,119’±5,183’±70’TBD Proposed
Bel_51-7 ±6,223’±6,300’±5,189’±5,258’±77’TBD Proposed
Bel_52-9 ±6,310’±6,374’±5,267’±5,325’±64’TBD Proposed
TY_ 56-9 6,801’6,832’5,702’5,732’31’4/17/23 Isolated
TY_62-5 7,412’7,426’6,231’6,244’14’4/7/23 Isolated
TY_62-5 7,437’7,461’6,253’6,269’24’3/27/23 Isolated
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
22”Conductor Weld Surf 28’
11-3/4"Surf Csg/Conductor 47.0 J-55 8RD 11.000”Surf 988’(TOW)
7-5/8”Int Csg/Surf Csg 29.7 L-80 BTC 6.875”Surf 2,743’
4-1/2"Prod Csg 12.6 L-80 DWC/C-HT 3.958”2,570’7,554’
4-1/2”Tieback 12.6 L-80 DWC/C-HT 3.958”Surface 2,569’
2
22”
11-3/4”
JEWELRY DETAIL
No.Depth ID OD Item
1 988’N/A 12.25”Whipstock
2 2,570’4.875”6.540”Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift, Seal 1.63’ off seat
3 ±6,751 CIBP w/ 35ft of cement
4 7,362’CIBP 4/17/23 - w/ 35ft of cement
5 7,427’3.5”CIBP 4/5/23
OPEN HOLE / CEMENT DETAIL
11-3/4”TOC @ Surface (Original 22-33)
7-5/8"TOC @ Surface (3/3/23)
4-1/2”TOC @ 2,561’ based on CBL, Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
RA Tags 5,605 & 6,092’
5
3
4
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.
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson
Cc:Noel Nocas; Donna Ambruz; Barney Phillips; Sarah Frey; Meredyth Richards; Guhl, Meredith D (OGC); Davies,
Stephen F (OGC)
Subject:RE: SRU 231-33 (PTD# 223-008) Additional plug
Date:Tuesday, April 25, 2023 5:09:00 PM
Chad,
Hilcorp has verbal approval to proceed with the plan outlined below. I will attach this email to the
proposed sundry that is currently in the review stage at AOGCC.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Tuesday, April 25, 2023 4:49 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Barney
Phillips <bphillips@hilcorp.com>; Sarah Frey <sarah.frey@hilcorp.com>; Meredyth Richards
<Meredyth.Richards@hilcorp.com>
Subject: SRU 231-33 (PTD# 223-008) Additional plug
Bryan,
As we discussed on the phone per SRU 231-33 PTD# 223-008 plug setting
Today we set a CIBP (rated for 10k differential pressure) at 6751’, everything went well with setting
the plug, as planned
When running in the well with a 3”OD 30ft long cement dump bailer we sat down early. When we
POOH with the bailer, the cement had dumped from the bailer.
Our subsequent run we ran a junk basket and gauge ring and correlated the tag depth to 6579’.
This top of cement is 172ft from the top of the plug (222ft from the top of the perfs)
We are requesting approval to set another CIBP ~6569’ (min of 5ft away from any collars) and place
35ft of cement on top of the plug for isolation between the Tyonek and Beluga Pools. The deepest
proposed perfs in the Beluga formation are 6374’, so we still have room to set plug at this depth.
We are currently running a 3.65 GR/JB to ensure there are no stringers above this interval.
Please let me know if you need any additional information and if we have approval to set the plug at
this depth.
Chad Helgeson
Operations Engineer
Kenai Asset Team
907-777-8405 - O
907-229-4824 - C
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
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CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:Chad Helgeson
To:McLellan, Bryan J (OGC); Davies, Stephen F (OGC)
Cc:Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] FW: SRU 231-33 (PTD#223-008) Sundry # 323-154 Additional perforations
Date:Tuesday, April 25, 2023 7:41:10 AM
Thanks Bryan,
We got the sundry submitted this morning.
Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, April 24, 2023 2:05 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: Re: [EXTERNAL] FW: SRU 231-33 (PTD#223-008) Sundry # 323-154 Additional perforations
Chad, Hilcorp has verbal approval to perforate the Beluga perfs requested in your email after abandoning the existing tyonek perfs
w/ CIBP and at least 25’ of cement. Please follow up with a sundry within 3 days. FYI the sundry is required here since you are
plugging one pool and opening another.
Sent from my iPhone
On Apr 24, 2023, at 12:08 PM, Davies, Stephen F (OGC) <steve.davies@alaska.gov> wrote:
Chad:
Thank you. I appreciate Hilcorp’s help with this.
Q: This seems like a unique request. Is this something we need to be prepared for on future perf adds?
A: Occasionally I make requests like this one when planned perforation intervals lie near pool boundaries and my well
log correlations are somewhat uncertain since we here at AOGCC do not have the benefit of seismic data to aid with
those correlations.
Thanks again and stay safe,
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.
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Friday, April 21, 2023 3:18 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] FW: SRU 231-33 (PTD#223-008) Sundry # 323-154 Additional perforations
Steve,
This seems like a unique request. Is this something we need to be prepared for on future perf adds?
Attached is the panel that should have the information you need, but please let us know if you need anything
additional.
Chad
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.
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Friday, April 21, 2023 7:28 AM
To: Chad Helgeson <chelgeson@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] FW: SRU 231-33 (PTD#223-008) Sundry # 323-154 Additional perforations
Chad,
Could Hilcorp’s project geologist please provide a cross-section that displays SRU 231-33 and SCU 341-04 (formerly
SCU 41-4) and is labeled with the current and proposed perforations along with the boundaries of the Beluga and
Tyonek Gas Pools as defined in CO 716A?
Thanks for your help,
Steve Davies
Alaska Oil and Gas Conservation Commission (AOGCC)
<image003.jpg>
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.
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Thursday, April 20, 2023 4:13 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>
Subject: SRU 231-33 (PTD#223-008) Sundry # 323-154 Additional perforations
Bryan,
We perforated all the sands that were Sundried in the Tyonek Structure and did not find any gas in our new drill well.
We would like to plug back the current open Tyonek sands, per approved Sundry# 323-154, where we will set a CIBP
within 50ft of the top perf and add 35ft of cement with a dump bailer and then add new perfs.
The following sands we would like to add are in the Beluga Pool. Attached are a current schematic and a Proposed
Schematic.
Interval Name MD Top MD BASE TVD Top TVD BASE FT
51-4 ±6,145’ ±6,215’ ±5,119’ ±5,183’ 70
51-7 ±6,223’ ±6,300’ ±5,189’ ±5,258’ 77
±6,310’ ±6,374’ ±5,267’ ±5,325’ 64
52-9
The perfs will be added following steps 9-13 of the approved sundry and the same contingencies may be necessary.
Let me know if you need any additional information, or if you have any questions.
Please let me know if we have approval to proceed with these additional perfs.
Thanks
Chad Helgeson
Operations Engineer
Kenai Asset Team
907-777-8405 - O
907-229-4824 - C
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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,
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The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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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
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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
Regg, James B (OGC)
From:Brooks, Phoebe L (OGC)
Sent:Thursday, April 20, 2023 10:20 AM
To:Cole Bartlewski
Cc:Regg, James B (OGC)
Subject:RE: BOPE test report for Fox Energy CTU 8 on SRU 231-33
Attachments:Fox 8 03-20-23 Revised.xlsx
Cole,
Attached is a revised report adding 1 to the Number of Failures based on the 1 “FP”. Please update your copy.
Thanks,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907‐793‐1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Cole Bartlewski <cbartlewski@hilcorp.com>
Sent: Friday, March 24, 2023 5:36 PM
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>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BOPE test report for Fox Energy CTU 8 on SRU 231‐33
Good afternoon,
BOPE test report attached for Fox Energy CTU 8 with 1.75” CT on Swanson River SRU 231‐33.
Have a great weekend.
Respectfully,
Cole Bartlewski
Hilcorp Alaska, LLC
Sr. Wellsite Supervisor
Email: cbartlewski@hilcorp.com
Office 907-283-1301
Cell 907-690-2854
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.
Swanson River Unit 231-33PTD 2230080
2
Hilcorp Alaska, LLC
A Company built on Energy
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
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:8 DATE:3/20/23
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2230080 Sundry #323-154
Operation:Drilling:Workover:X Explor.:
Test:Initial:X Weekly:Bi-Weekly:Other:
Rams:250/3000 Annular:Valves:250/3000 MASP:2112
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 0 NA
Permit On Location P Hazard Sec.P Lower Kelly 0 NA
Standing Order Posted P Misc.NA Ball Type 0 NA
Test Fluid Water Inside BOP 0 NA
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 1 1.75"P Trip Tank NA NA
Annular Preventer 0 NA NA Pit Level Indicators NA NA
#1 Rams 1 1.75" B/S P Flow Indicator NA NA
#2 Rams 1 1.75" P/S P Meth Gas Detector NA NA
#3 Rams 0 NA NA H2S Gas Detector NA NA
#4 Rams 0 NA NA MS Misc 0 NA
#5 Rams 0 NA NA
#6 Rams 0 NA NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 2 2"FP Time/Pressure Test Result
HCR Valves 0 NA NA System Pressure (psi)3000 P
Kill Line Valves 2 2"P Pressure After Closure (psi)2500 P
Check Valve 0 NA NA 200 psi Attained (sec)3 P
BOP Misc 0 NA NA Full Pressure Attained (sec)9 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):0 NA
No. Valves 5 P ACC Misc 0 NA
Manual Chokes 2 P
Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 0 NA
#1 Rams 24 P
Coiled Tubing Only:#2 Rams 24 P
Inside Reel valves 1 P #3 Rams 0 NA
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:1 Test Time:3.0 HCR Choke 0 NA
Repair or replacement of equipment will be made within days. HCR Kill 0 NA
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 03/19/2023
Waived By
Test Start Date/Time:3/20/2023 12:00
(date)(time)Witness
Test Finish Date/Time:3/20/2023 15:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Jim Regg
Fox
FP on choke line valve was due to a drip on the 1502 iron from test pump. Replaced 1502 seal and retest was good.
Landry Lynn
Hilcorp
Cole Bartlewski
SRU 231-33
Test Pressure (psi):
trais@foxenergyak.com
Cbartlewski@hilcorp.com
Form 10-424 (Revised 08/2022)2023-0320_BOP_Fox_CTU8_SRU_231-33
Hilcorp Alaska LLC jbr
jbr
J. Regg
Kyle Wiseman Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: Kyle.Wiseman@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 04/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230414
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
MPF-81 50029229590000 200066 3/29/2023 READ CaliperSurvey
MPI-04A 50029220680100 201092 4/2/2023 READ CaliperSurvey
MPI-27 50029236920000 221013 4/2/2023 READ CaliperSurvey
MPI-27 50029236920000 221013 3/20/2023 READ CaliperSurvey
MPL-12 50029223340000 193011 4/2/2023 READ CaliperSurvey
MPU I-27 50029236920000 221013 3/23/2023 READ LeakPointSurvey
PBU 09-23A 50029210660100 198044 3/28/2023 READ MultipleArrayProductionProfile
PBU L-112A 50029231290100 222138 3/27/2023 READ MemoryRadialCementBondLog
END 1-11 50029221070000 190157 3/19/2023 AK E-LINE Perf
END 1-29 50029216690000 186181 2/9/2023 AK E-LINE Perf
NCI A-08 50883200280000 169063 3/20/2023 AK E-LINE Perf
BCU 19RD 50133205790100 219188 4/4/2023 AK E-LINE PPROF
SRU 224-10 50133101380100 222124 3/31/2023 AK E-LINE CIBP_GPT_Perf
SRU 224-10 50133101380100 222124 4/3/2023 AK E-LINE GPT_Perf
SRU 231-33 50133101630100 223008 3/29/2023 AK E-LINE GPT
Please include current contact information if different from above.
T37595
T37596
T37599
T37599
T37597
T37599
T37598
T37601
T37603
T37600
T37602
T37594
T37604
T37604
T37605SRU 231-33 50133101630100 223008 3/29/2023 AK E-LINE GPT
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.04.17
14:10:44 -08'00'
Kyle Wiseman Hilcorp Alaska, LLC 2 2 231-bb
Geo Tech 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503 g
Tele: (907) 564-4558
thirtirp: aska,r.lX E-mail: kyle.wiseman@hilcorp.com
Date: 04/03/2023
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
SRU 231-33 (PTD 223-008)
(API 50-133-10163-01-00)
Washed and Dried Well Samples (03/10/2023)
A Set (5 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET i MD)
SRU 231-33
BOX 1 OF 5
988' - 2640' MD
SRU 231-33
BOX 2 OF 5
2640' - 41 10'MD
SRU 231-33
BOX 3 OF 5
4110' - 5280' MD
SRU 231-33
BOX 4 OF 5
5280' - 6360' MD
SRU 231-33
BOX 5 OF 5
6360' - 7554' MD
Total Dry Bag Count: 219
Please include current contact information if different from above.
RECEIVED
APR 0 3 2023
AOGCC
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422
Received y: Date:
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: 03/29/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
FINAL LWD FORMATION EVALUATION LOGS (02/23/2023 to 03/10/2023)
ROP, EWR-M5, AGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
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: 03/29/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
MUDLOGS - EOW DRILLING REPORTS (02/27/2023 to 03/10/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
a. Formation Log
b. LWD Combo Log
c. Gas Ratio Log
d. Drilling Dynamics Log
Folder Contents:
Please include current contact information if different from above.
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.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson
Cc:Donna Ambruz
Subject:RE: SRU 231-33 (PTD 223-008) initial perf sundry 323-154 CBL
Date:Thursday, March 23, 2023 9:52:00 AM
Chad,
Cement bond looks good. Hilcorp has approval to proceed with the perforating per sundry 323-154.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Thursday, March 23, 2023 9:40 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: SRU 231-33 (PTD 223-008) initial perf sundry 323-154 CBL
Bryan,
Please find attached a CBL for SRU 231-33. Please provide approval for perforating proposed zones
in the well. The plan is to start perforating these sands tomorrow.
Let me know if you have any questions on the log.
Thanks
Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, March 17, 2023 2:48 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: [EXTERNAL] SRU 231-33 (PTD 223-008) initial perf sundry 323-154 verbal approval
Chad,
Hilcorp has verbal approval to begin the operations on SRU 231-33 outlined in the sundry application
submitted on 3/14/23. FYI this sundry has been assigned number 323-154.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
From:McLellan, Bryan J (OGC)
To:chelgeson@hilcorp.com
Subject:SRU 231-33 (PTD 223-008) initial perf sundry 323-154 verbal approval
Date:Friday, March 17, 2023 2:48:00 PM
Chad,
Hilcorp has verbal approval to begin the operations on SRU 231-33 outlined in the sundry application
submitted on 3/14/23. FYI this sundry has been assigned number 323-154.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
1
Regg, James B (OGC)
From:Rance Pederson - (C) <rpederson@hilcorp.com>
Sent:Wednesday, March 15, 2023 6:20 AM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT Hilcorp 169
Attachments:MIT Hilcorp 169 03-14-23.xlsx; SRU 231-33 MIT-T and MIT-IA Chart.pdf
Please see the attached form and chart for SRU 231‐33 MIT‐T and MIT‐IA
Rance Pederson
Drilling Foreman
Swanson River Unit
907‐283‐1369
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
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Swanson River Unit 231-33PTD 2230080
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230080 Type Inj N Tubing 0 3040 3030 3025 Type Test P
Packer TVD 2391'BBL Pump 1.2 IA 0 45 48 48 Interval I
Test psi 3000 BBL Return 1.2 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230080 Type Inj N Tubing 0 109 106 105 Type Test P
Packer TVD 2391'BBL Pump 0.8 IA 0 2520 2520 2520 Interval I
Test psi 2500 BBL Return 0.8 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:7 5/8" x 4 1/2" Annulus. ZXP Liner Top Packer at 2391' tvd. Winess waived by Jim Regg on 3-14-23 at 09:32
Notes:
Notes:
Hilcorp Alaska, LLC
Swanson River Field, Swanson River Unit, Pad 23-33
Rance Pederson
03/14/23
Notes:4 1/2" Tieback String and Liner. ZXP Liner Top Packer at 2391' tvd. Winess waived by Jim Regg on 3-14-23 at 09:32
Notes:
Notes:
Notes:
SRU 231-33
SRU 231-33
Form 10-426 (Revised 01/2017)2023-0314_MITP_SRU_231-33_2tests
J. Regg; 5/3/2023
jbr
jbr
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
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?
Will planned perforations require a spacing exception? Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
Swanson River
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
7,554 N/A
Casing Collapse
Structural
Conductor
Surface 1,510psi
Intermediate 4,790psi
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name: Chad Helgeson
Contact Email:chelgeson@hilcorp.com
Contact Phone:(907) 777-8405
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:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
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:
AOGCC USE ONLY
Operations Manager
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size:
12.6 / L-80 2,570
3/20/2023
Liner Top Pkr & N/A 2,570 (MD) 2,404 (TVD) & N/A
N/A N/A 4-1/2"
6,880psi
3,070psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
A028399
223-008
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-133-10163-01-00
Hilcorp Alaska, LLC
Swanson River Unit (SRU) 231-33
N/A
Sterling/Beluga Gas, Tyonek
Gas, Beluga Gas
CO 716A
Burst
PRESENT WELL CONDITION SUMMARY
N/A7,467
988
2,529
Perforation Depth MD (ft):
4,984 4-1/2"
7-5/8"2,743
11-3/4"988 988
2,743
8,430psi6,3557,554
Other: CT Operations /
N2 Operations
6,355 6,280 2,112
22"28
MD
28 28
Length Size
Proposed Pools:
TVD
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Samantha Carlisle at 7:43 am, Mar 14, 2023
323-154
Digitally signed by Noel Nocas
(4361)
DN: cn=Noel Nocas (4361),
ou=Users
Date: 2023.03.13 16:20:03 -08'00'
Noel Nocas
(4361)
x
Perforate New Pool
BJM 3/17/23 DSR-3/14/23
CT BOP test to 3000 psi.
Submit CBL to AOGCC and obtain approval prior to perforating.
MDG Tyonek
Gas,
Yes 3/17/23
Bryan McLellan
XCT
10-407
MDG 3/14/2023GCW 03/20/23JLC 3/20/2023
3/20/23
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.03.20 10:29:23
-08'00'
RBDMS JSB 032123
Well Work Prognosis
Well Name:Swanson River 231-33 API Number:50-133-10163-01-00
Current Status:Gas Producer Rig:Eline & Fox CTU
Estimated Start Date:3/20/23
Regulatory Contact:Donna Ambruz (8305)Permit to Drill Number:223-008
First Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (M)
Second Call Engineer:Frank Roach (907) 854-2321 (M)
Maximum Expected BHP 2,738psi @ 6,269’ TVD Based on 8.4ppg gradient
Maximum Potential Surface Pressure: 2,112 psi @ 6,269’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4)
Brief Well Summary
Swanson River 231-33 is a sidetracked gas producer that was drilled and completed to 7,554ft. The
wellbore is completed as a 4-1/2” mono-bore with tieback to surface, the tubing will be tested to 3,000
psi and casing to 3000 psi.
The purpose of this sundry is to cleanout the well to 7567’ with coil tubing, run a CBL, swap fluids in the
well to Nitrogen and add perfs in the Tyonek Pool/PA.
Notes Regarding Wellbore Condition
x 4-1/2” mono-bore completion
x Liner/seal assembly @ 2,570’
x 4-1/2” liner currently filled with 9.2 ppg 6% KCl drilling mud
Procedure:
1. Review all approved COAs
2. MIRU Fox Coiled Tubing Unit, PT BOPE to 3,000 psi High/250 psi Low
3. Provide AOGCC 24hrs notice of BOP test
4. PU motor & mill, RIH and cleanout well to 7,467’
5. Circ out 9.2 ppg mud to 8.4 ppg water
6. PU CBL memory tool and complete CBL from PBTD to liner top
7. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen, leave N2 pressure on
well to desired underbalance from the Reservoir Engineer (expect ~1500-2000psi)
a. Ensure tank is strapped from same spot in tank to measure total volume of recovered
water from well (114bbls from well)
b. If 114 bbls isn’t recovered RU a Reverse circ out manifold and reverse out water.
8. RDMO coil tubing
9. RU E-line, PT lubricator to 3000 psi High/250 psi Low
10. Perforate Tyonek sands in individual tests to determine productivity from each sand.
Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist.
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT
TY_ 56-9 ±6,801 ±6,834 ±5,702 ±5,732 ±33’
TY_ 61-0 ±7,045 ±7,147 ±5,915 ±6,003 ±102’
TY_62-5 ±7,412 ±7,426 ±6,231 ±6,244 ±14’
TY_62-5 ±7,437 ±7,461 ±6,253 ±6,269 ±24’
Send CBL log to AOGCC and obtain approvol prior to
perforating. -bjm
add perfs in the Tyonek Pool/PA.
Well Work Prognosis
a. Record initial and 5/10/15 minute tubing pressures after firing
b. Above perfs will be shot in the Tyonek Gas Pool governed by CO 716A
11. RD E-Line Unit and turn well over to production
12. Operations to flow well and test zones
13. Test SVS as per 20 AAC 25.265 once stable flow is achieved
a) Notify AOGCC 24hrs in advance of testing SVS
E-line Procedure (Contingency)
If any zone produces sand and/or water or needs isolated:
14. MIRU Eline and N2 pump truck
15. Pressure test equipment to 4,000 psi High/250 psi Low
16. Eline run PT to find fluid level
17. RU N2 and push fluid below perfs (verify fluid depth with PT tool)
18. PU 4-1/2” CIBP or patch
a. If a plug is set (it must be set within 50ft of the top perf being plugged back)
b. Dump bail 35ft of cement on top of plug (unless there isn’t enough room to the next
perf)
c. Any CIBP with less than 35’ of cement will need approval from BLM prior to adding next
set of perfs
19. If necessary to cleanout or unload well with coiled tubing, RU same coil equipment used in initial
completion
a. Test BOPs, 3,000 psi High/ 250 psi Low
b. Cleanout with N2 or foam
c. Set 4-1/2” plug or patch (cement as required in Step 18)
Attachments:
1. Proposed Well Schematic
2. Wellhead Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
5. AOGCC RWO Change Form
Updated by CAH 03-13-2023
PROPOSED
Swanson River Unit
SRU 231-33
PTD: 223-008
API: 50-133-10163-01-00
PBTD = 7,467’ / TVD = 6,280’
TD = 7,554’ / TVD = 6,355’
RKB to GL = 18.0’
Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status
TY_ 56-9 ±6801 ±6834 ±5702 ±5732 ±33’ TBD Proposed
TY_ 61-0 ±7045 ±7147 ±5915 ±6003 ±102’ TBD Proposed
TY_62-5 ±7412 ±7426 ±6231 ±6244 ±14’ TBD Proposed
TY_62-5 ±7437 ±7461 ±6253 ±6269 ±24’ TBD Proposed
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
22” Conductor Weld Surf 28’
11-3/4" Surf Csg/Conductor 47.0 J-55 8RD 11.000” Surf 988’(TOW)
7-5/8” Int Csg/Surf Csg 29.7 L-80 BTC 6.875” Surf 2,743’
4-1/2" Prod Csg 12.6 L-80 DWC/C-HT 3.958” 2,570’ 7,554’
4-1/2” Tieback 12.6 L-80 DWC/C-HT 3.958” Surface 2,570’
2
22”
11-3/4”
JEWELRY DETAIL
No. Depth ID OD Item
1 988’ N/A 12.25” Whipstock
2 2,570’ 4.875” 6.540”
Liner Top Packer, Flex-Lock V Liner hanger, HRD-E
ZXP w/ 5.78”PBR. 3.833 Drift
OPEN HOLE / CEMENT DETAIL
11-3/4” TOC @ Surface (Original 22-33)
7-5/8" TOC @ Surface (3/3/23)
4-1/2”Plan TOC @ TOL (2,589’), Pumped 30 bbl 10.5 ppg spacer, 158 bbls (380 sx) of 12
ppg Type 1 & II cement, 19 bbls of 15.3 ppg Type 1 & II, 50 bbls cmt returns.
4
7-5/8”
1
SRU 23-33
(Abandoned)
4-1/2”
Notes:
RA Tags 5,605 & 6,092’
Swanson River
SRU 231-33 Proposed
2/15/2023
Valve, Master, CIW-FLS,
4 1/16 5M FE, HWO,
EE trim
Valve, Upper master,
CIW-FLS,
4 1/16 5M FE, HWO, EE trim
Valve, Swab, CIW-FLS
4 1/16 5M FE, HWO,
EE trim
Valve, Wing, CIW-FC,
3 1/8 5M FE, HWO,
EE trim
BHTA, Bowen, 4 1/16 5M FE
x 7'’ Bowen quick union top
16'’ x 11 ¾ bushing
7 5/8'’
4 ½’’
Starting head, Cactus C-29L,
16 3/4 3M x 16 SOW, w/ 2- 2
1/16 5M SSO
Tubing head, Cactus C-29L-
HPS, 16 3/4 3M x 11 5M, w/
2- 2 1/16 5M SSO
SRU 231-33
11 3/4 x 7 5/8 x 4 ½
Tubing hanger, Cactus-EN-
CCL, 4 ½ EUE 8rd lift and
susp x w 6 ¼ od ext neck, 4'’
type H BPV profile, DD-NL
material
Valve, Wing, SSV, WKM-M,
3 1/8 5M FE, w/ 15'’ Hydraulic
operator
Adapter, Cactus-EN-6.25'’,
11 5M stdd x 4 1/16 5M stdd
top, w/ 2- 1'’npt control line
exits
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well SRU 231-33 (PTD 223-008)Sundry #: TBDAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________SWANSON RIV UNIT 231-33
JBR 04/05/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Took a while to get a shell test to 5 K. Precharge for bottles was 15 @ 1000. Blind rams failed and doors weree opened and
seals looked good but dirty. They were cleaned and passed re-test. Bag F/P, pressure had to be turned up to get them to pass.
Test Results
TEST DATA
Rig Rep:Brandon DavisOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley
Rig Owner/Rig No.:Hilcorp 169 PTD#:2230080 DATE:3/4/2023
Type Operation:DRILL Annular:
250/2500Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopRCN230305152955
Inspector Bob Noble
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7.5
MASP:
2237
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 none NA
Annular Preventer 1 11"FP
#1 Rams 1 2 7/8" x 5"P
#2 Rams 1 Blinds FP
#3 Rams 1 2 7/8" x 5"P
#4 Rams 0 none NA
#5 Rams 0 none NA
#6 Rams 0 none NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 2 1/16" , 3 1/8 P
Kill Line Valves 1 2 1/16"P
Check Valve 0 none NA
BOP Misc 0 none NA
System Pressure P3050
Pressure After Closure P1550
200 PSI Attained P25
Full Pressure Attained P97
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4 @ 2450
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P18
#1 Rams P3
#2 Rams P4
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9
9
9999
9
9
9
Blind rams failed
Bag F/P,
FP
FP
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________SWANSON RIV UNIT 231-33
JBR 04/17/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Tested all gas alarms and PVT's, Precharge Bottles = 15 each (8 @ 1000psi and 7 @1050psi).
TEST DATA
Rig Rep:M. DavisOperator:Hilcorp Alaska, LLC Operator Rep:J. Murphy
Contractor/Rig No.:Hilcorp 169 PTD#:2230080 DATE:2/26/2023
Well Class:DEV Inspection No:divBDB230228065804
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:9.88 P
Vent Line(s) Size:16 P
Vent Line(s) Length:101 P
Closest Ignition Source:83 P
Outlet from Rig Substructure:87 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:36 P
Knife Valve Open Time:2 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1650
200 psi Recharge Time:P16
Full Recharge Time:P97
Nitrogen Bottles (Number of):P4
Avg. Pressure:P2450
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
9 9
9
9 9
9
9
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: Swanson River Field, Sterling/Beluga, Tyonek, and Beluga Gas Pools, SRU 231-33
Hilcorp Alaska, LLC
Permit to Drill Number: 223-008
Surface Location: 1717’ FSL, 1715’ FWL, Sec 33, T8N, R9W, SM, AK
Bottomhole Location: 662’ FNL, 1452’ FEL, Sec 33, T8N, R9W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of February, 2023. 10
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.02.10 13:28:46
-09'00'
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: 7,583' TVD: 6,392'
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): 158.2' 15. Distance to Nearest Well Open
Surface: x-344086 y- 2462919 Zone-4 140.2' to Same Pool:1300' to SRU 241-33B
16. Deviated wells:Kickoff depth: 1,000 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 42 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
9-7/8" 7-5/8" 29.7# L-80 BTC 2,789' Surface Surface 2,789' 2,558'
6-3/4" 4-1/2" 12.6# L-80 DWC/C-HT 4,994' 2,589' 2,411' 7,583' 6,392'
Tieback 4-1/2" 12.6# L-80 DWC/C-HT 2,589' Surface Surface 2,589' 2,411'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
N/A
TVD
28'
1,756'
10,895'
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
2/15/2023
1582' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
907-777-8413
28'
1,756'11-3/4"1200 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):
1,756'
2500 sxProduction
Liner
10,895'
Intermediate
N/A
Conductor/Structural 22"28'
Authorized Title:
Authorized Signature:
Authorized Name:
10,895'10,895'
LengthCasing
6,645'
Cement Volume MDSize
Plugs (measured):
(including stage data)
L - 758 ft3 / T - 182 ft3
L - 889 ft3 / T - 104 ft3
6,645'6,645'
Effect. Depth MD (ft):Effect. Depth TVD (ft):
1760
18. Casing Program:Top - Setting Depth - BottomSpecifications
2876
GL / BF Elevation above MSL (ft):
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Tieback Assy.
2237
2362’ FSL, 2146’ FWL, Sec 33, T8N, R9W, SM, AK
662’ FNL, 1452’ FEL, Sec 33, T8N, R9W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
1717’ FSL, 1715’ FWL, Sec 33, T8N, R9W, SM, AK A028399
SRU 231-33
Swanson River Unit
Tyonek Gas Pool
Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
N/A
10,895'7"
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
s
D
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
2.1.2023
By Samantha Carlisle at 1:05 pm, Feb 01, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.01 12:37:31 -09'00'
Monty M
Myers
Swanson River
50-133-10163-01-00
BJM 2/5/23 SFD 2/9/2023
Initial BOP test to 3500 psi/Annular test to 2500 psi.
Submit FIT/LOT results to AOGCC within 48 hrs of performing test.
SFD
223-008
Redrilll
Sterling/Beluga Gas Pool
DSR-2/1/23GCW 02/10/23
JLC 2/10/2023
2/10/23
2/10/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.02.10 13:29:05 -09'00'
SRU 231-33
Drilling Program
Swanson River Unit
Rev 0
January 16, 2023
SRU 231-33
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 Current (Post P&A) Wellbore Schematic ...............................................................................................6
7.0 Planned Wellbore Schematic...................................................................................................................7
8.0 Drilling / Completion Summary..............................................................................................................8
9.0 Mandatory Regulatory Compliance / Notifications ................................................................................9
10.0 R/U and Preparatory Work...................................................................................................................12
11.0 N/U 21-1/4” 2M Diverter .......................................................................................................................13
12.0 Set Whipstock / Mill Window................................................................................................................15
13.0 Drill 9-7/8” Hole Section ........................................................................................................................16
14.0 Run 7-5/8” Surface Casing ....................................................................................................................18
15.0 Cement 7-5/8” Surface Casing...............................................................................................................21
16.0 BOP N/U and Test .................................................................................................................................24
17.0 Drill 6-3/4” Hole Section ........................................................................................................................25
18.0 Run 4-1/2” Production Liner .................................................................................................................28
19.0 Cement 4-1/2” Production Liner ...........................................................................................................31
20.0 4-1/2” Liner Tieback Polish Run and Cleanout Run ............................................................................35
21.0 4-1/2” Tieback Run ................................................................................................................................35
22.0 RDMO....................................................................................................................................................35
23.0 Diverter Schematic................................................................................................................................36
24.0 BOP Schematic......................................................................................................................................37
25.0 Current Wellhead Schematic.................................................................................................................38
26.0 Wellhead Schematic...............................................................................................................................39
27.0 Days Vs Depth........................................................................................................................................40
28.0 Geo-Prog................................................................................................................................................41
29.0 Anticipated Drilling Hazards.................................................................................................................42
30.0 Hilcorp Rig 169 Layout .........................................................................................................................44
31.0 FIT/LOT Procedure...............................................................................................................................45
32.0 Choke Manifold Schematic....................................................................................................................46
33.0 Casing Design Information....................................................................................................................47
34.0 6-3/4” Hole Section MASP.....................................................................................................................48
35.0 Spider Plot (Governmental Sections) ....................................................................................................49
36.0 660’ Radius for SSSV.............................................................................................................................50
37.0 Surface Plat (As-Built NAD27 & NAD83).............................................................................................51
Page 2 Version 0 December, 2022
SRU 231-33
Drilling Procedure
Rev 0
1.0 Well Summary
Well SRU 231-33
Pad & Old Well Designation SRU 23-33 Pad
Planned Completion Type 4-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga/Tyonek
Planned Well TD, MD / TVD 7,583 MD / 6,392’ TVD
PBTD, MD / TVD 7,503’ MD / 6,321’TVD
Surface Location (Governmental)1717’ FSL, 1715’ FWL, Sec 33, T8N, R9W, SM, AK
Surface Location (NAD 27)X=344086.85 Y=2462919.59
Surface Location (NAD 83)X=1484109.70 Y=2462680.94
Top of Productive Horizon
(Governmental)2362’ FSL, 2146’ FWL, Sec 33, T8N, R9W, SM, AK
TPH Location (NAD 27)X=344523.74, Y=2463565.24
TPH Location (NAD 83)X=1484546.62 Y=2463326.58
BHL (Governmental)662’ FNL, 1452’ FEL, Sec 33, T8N, R9W, SM, AK
BHL (NAD 27)X=346231.00, Y=2465801.00
BHL (NAD 83)X=1486253.97 Y=2465562.32
AFE Number
AFE Drilling Days 4 MOB, 19 DRLG
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2237 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)2876 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 158.2’(140.2 + 18.0)
Ground Elevation 140.2’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Sterling/Beluga/Tyonek
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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)
Surface
9-7/8”7-5/8”6.875”6.750”8.500”29.4 L-80 BTC 6880 4790 683
Prod
6-3/4”4-1/2”3.958”3.833”5.000”12.6 L-80 DWC/C-HT 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area –this will not save the data entered, and will navigate to another data entry
tab.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a
username to login with.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run”Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
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6.0 Current (Post P&A) Wellbore Schematic
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7.0 Planned Wellbore Schematic
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8.0 Drilling / Completion Summary
SRU 231-33 is a directional development well to be drilled from SRU 23-33 Pad. Reservoir analysis and
subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga
sands.
The base plan is a directional wellbore out of SRU 23-33. The surface hole will be redrilled with an exit in
the 11-3/4” surface casing. The existing 11-3/4” casing will become the conductor. Maximum hole angle
will be 42 deg. and TD of the well will be 7,583’ TMD/ 6,392’ TVD, ending with 28 deg inclination left in
the hole.
Drilling operations are expected to commence approximately February 15
th, 2023. The Hilcorp Rig # 169 will
be used to drill the wellbore then run casing and cement.
7-5/8” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater
resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed,
a cement evaluation log (CBL/VDL or temperaturelogfor example) will be run to determine TOC. Necessary
remedial action will then be discussed with AOGCC/BLM authorities.
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.
General sequence of operations:
1. MOB Hilcorp Rig # 169 to well site
2. N/U diverter and test.
3. Run 11-3/4” whipstock and set at ~1000’. Mill Window.
a. Gyro required for setting WS and casing departure
4. Drill 9-7/8”hole to 2,789’ MD. Run and cmt 7-5/8”surface casing.
5. ND diverter, N/U & test 11” x 5M BOP.
6. Drill 6-3/4” hole section to 7,583’MD. Perform Wiper trip.
7. POOH laying down drill pipe.
8. Run and cmt 4-1/2”production liner.
9. PU polish mill assembly and RIH to polish sealbore
10. RIH and land 4-1/2” tieback string in liner top.
11. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: GR + Res LWD
2. Production Hole: Triple Combo LWD
3. Mud loggers from surface casing point to TD.
a directional wellbore out of SRU 23-33. The surface hole will be redrilled with an exit in p
the 11-3/4” surface casing. T
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9.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations and all
BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how
to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during drilling. Ensure to provide AOGCC 24 hrs notice
prior to testing BOPs. And BLM 48 hrs notice prior to testing.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x Required Rated Working Pressure the BOPE and wellhead must meet or exceed:
o 3000 psi. for the 6-3/4” hole section
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man
office.
x Review all conditions of approval of the AOGCC PTD on the 10-401 form and the BLM APD.
Ensure that the conditions of approval are captured in shift handover notes until they are executed
and complied with.
Regulation Variance Requests:
x BLM:
o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to install a 2-1/16” 5M HCR
valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with
installation of a check valve in the kill line.
o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to utilize flexible choke and kill
lines in lieu of hard piping.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Required BLM Notifications:
x 48 hours before spud. Follow up with actual spud date and time within 24 hours.
x 72 hours before casing running and cmt operations
x 72 hours before BOPE tests
x 72 hours before logging, coring, & testing
x Any other notifications required in APD
Additional requirements may be stipulated on APD and Sundry.
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Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
BLM
Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127
Email: aschoessler@blm.gov
Use the below email address for BOP notifications to the BLM:
BLM_AK_AKSO_EnergySection_Notifications@blm.gov
2016 Waste Prevention Rule -
Waste Minimization Plan for Drilling:
Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced
from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility
for beneficial reuse, if possible after testing, and disposal.
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10.0 R/U and Preparatory Work
10.1 Cut off old wellhead from 11-3/4” casing and install slip-on “A” section post
abandonment/sidetrack prep work completed by rig 401. Ensure to orient wellhead so that tree
will line up with flowline later.
10.2 Level pad and ensure enough room for layout of rig footprint and R/U.
10.3 Layout Herculite on pad to extend beyond footprint of rig.
10.4 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
10.5 RU Mud loggers on surface hole section for gas detection only. No samples required
10.6 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
10.7 Mix mud for 9-7/8”hole section.
10.8 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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11.0 N/U 21-1/4” 2M Diverter
11.1 N/U 21-1/4” diverter system.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE: Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
11.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
11.4 Set wear bushing in wellhead.
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11.5 Rig 169 and estimated Diverter line orientation on SRU 23-33 Pad:
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12.0 Set Whipstock / Mill Window
12.1 MU WIS mechanical set whipstock with UBHO.
x RU GyroData for tray face orientation while setting whipstock.
12.2 RIH on drillpipe to whipstock setting depth.
x Exercise caution when running in, setting slips, and picking up out of slips to avoid
prematurely setting the whipstock or shearing mills off of whipstock.
x Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly.
x Avoid sudden starts and stops while running the whipstock.
x Recommend 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.
12.3 Circulate the hole to clean window milling fluid.
12.4 Run gyro to orient whipstock as directed by the directional driller. The directional plan specifies
~20 deg azimuth.
12.5 Set the top of the whipstock at ~1,000 MD
x Pre-rig abandonment work will include a log with CCL to mitigate milling through
coupling.
12.6 Mill window plus 20’.
12.7 Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes.
12.8 POOH and LD milling assembly
x Inspect and gauge mills for wear and to ensure window is in spec. Record these values in the
morning report.
12.9 Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure
BOP equipment is operable.
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13.0 Drill 9-7/8”Hole Section
13.1 P/U 9-7/8”departure assy:
x Departure assembly to include motor, directional LWD, and UBHO for wireline gyro.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
13.2 4-1/2”Workstring & HWDP will come from Hilcorp.
13.3 Begin drilling out from 11-3/4”window at reduced flow rates and gradually ramp up to full
drilling rate.
13.4 Drill ahead per directional plan until gravity toolface achieved by LWD directional or able to bury
triple-combo BHA in openhole (not rotating density/neutron tool across whipstock).
13.5 POOH, LD UBHO and RD eline/gyro unit.
13.6 P/U 9-7/8” drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Workstring will be 4.5” 16.6# S-135 CDS40
13.7 Drill 9-7/8”hole section to 2,789’MD/ 2,558’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Kenai and Inlet experience to drill through coal seams efficiently. Coal seam log will
be provided by Hilcorp Geo team.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x TD the hole section in a good shale between 2750’ MD and 2850’ MD.
x Take MWD surveys every stand drilled (60’ intervals).
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13.8 9-7/8”hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 9.0 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 9.0 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
1000-2789’ 9.0 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
13.9 At TD; pump sweeps, CBU, and pull a wiper trip back to the 11-3/4”window.
13.10 TOH with the drilling assy, handle BHA as appropriate.
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14.0 Run 7-5/8”Surface Casing
14.1 R/U and pull wearbushing.
14.2 R/U Weatherford 7-5/8”casing running equipment.
x Ensure 7-5/8”BTC x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
14.3 P/U shoe joint, visually verify no debris inside joint.
14.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
14.5 Continue running 7-5/8”surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values
required to achieve this position.
x After making up several connections (minimum of 5), use the torque required to M/U to base
of triangle as the M/U torque and continue running string. Spot check every 10 joints to
confirm torque value used is adequate for proper make up.
x Install (1) centralizer every other joint to 300’.
x Do not install centralizers on the 2 joints above and below the window to keep
centralizers from moving across the window when reciprocating string on bottom.
x Do not run any centralizers above 300’ in the event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
7-5/8” 29.7# BTC M/U torques
Casing OD Makeup
7-5/8”To Mark
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14.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
14.7 Slow in and out of slips.
14.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
14.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
14.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
14.11 After circulating, lower string and land hanger in wellhead again.
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15.0 Cement 7-5/8”Surface Casing
15.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
15.2 Document efficiency of all possible displacement pumps prior to cement job
15.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly.
15.4 Pump 5 bbls spacer. Test surface cmt lines.
15.5 Pump remaining spacer.
15.6 Drop bottom plug. Mix and pump cmt per below recipe.
15.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead &
tail, TOC brought to surface.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
11-3/4”Conductor x 7-5/8”
casing annulus:
1000’ x .06106 bpf =61.06 342.9
12.0 ppg LEAD:
9-7/8”OH x 7-5/8”Casing
annulus:
(2289’ –1000’) x .03825 bpf x
1.5 =
73.96 415.2
Total LEAD:135.02 bbl 758.1 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(2789’- 2289’)x .03825 bpf x
1.5 =
28.69 161.1
15.4 ppg TAIL:
7-5/8”Shoe track:
80 x .04592 bpf =3.67 20.6
Total TAIL:32.36 bbl 181.7 ft3
TOTAL CEMENT VOL:167.38 bbl 939.8 ft3
Verified cement volumes. -bjm
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Cement Slurry Design:
15.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
15.9 After pumping cement, drop top plug and displace cement with spud mud.
15.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
15.11 Displacement calculation:
2789’-80’ = 2709’x .04592 bpf = 125 bbls
15.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
15.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 5.9 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 –18 hours after CIP.
x Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is
1.5”.
Lead Slurry (2289’ MD to surface)Tail Slurry (2789’ to 2289’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.40 ft3/sk 1.16 ft3/sk
Mixed Water 14.25 gal/sk 5.04 gal/sk
Mixed Fluid 14.25 gal/sk 5.04 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
CalSeal Accelerator CalSeal Accelerator
VersaSet Thixotropic CFR-3 Dispersant
D-Air 5000 Anti Foam UCS Slurry Conditioner
Econolite Light-weight add.Super CBL Anti-Gas Migration
SA-1015 Suspension Agent
BridgeMaker II Lost Circulation
Verified volume. -bjm
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15.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
15.15 R/D cement equipment. Flush out wellhead with FW.
15.16 Back out and L/D landing joint. Flush out wellhead with FW.
15.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
15.18 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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16.0 BOP N/U and Test
16.1 ND Diverter line and diverter
16.2 N/U multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
16.3 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.
16.4 Run 4-1/2”BOP test assy, land out test plug (if not installed previously).
x Utilize both 4-1/2” and 2-7/8” test joints in the event a cleanout of the 4-1/2” liner is
necessary.
x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
16.5 R/D BOP test assy.
16.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
16.7 Mix 9.0 ppg 6% KCL PHPA mud system.
16.8 R/U mud loggers for production hole section.
16.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
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17.0 Drill 6-3/4” Hole Section
17.1 Pull test plug, run and set wear bushing
17.2 Ensure BHA components have been inspected previously.
17.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
17.4 TIH, Conduct shallow hole test of MWD and confirm all LWD functioning properly.
17.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
17.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
17.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
17.8 6-3/4” hole section mud program summary:
Starting mud weight for the production interval is 9.0 ppg or the surface interval mud weight at
TD, whichever is heavier.
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.
System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
2,789’-7,583’9.0 –10.0 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 –10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
17.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
17.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8” burst is 6890 psi / 2 = 3445 psi.
17.11 Drill out shoe track and 20’ of new formation.
17.12 CBU and condition mud for FIT.
17.13 Conduct FIT to 12.6 ppg EMW.
Note: Offset field test data predicts frac gradient at the 7-5/8”shoe to be between 11 - 15 ppg
EMW. A 12.6 ppg FIT results in a > 15 bbl kick tolerance volume while drilling with the
planned MW of 9.5 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
17.14 Drill 6-3/4” hole section to 7,583’ MD / 6,392’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x On the third wiper trip (around 5,200’ MD), trip back to the 7-5/8” shoe to split the hole
section in half
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed
necessary.
x Take (3) sets of formation samples every 20’.
17.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8”shoe.
ff f p f g
A 12.6 ppg FIT results in a > 15 bbl kick tolerance volume while drilling with theppg g
planned MW of 9.5 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
pp
7-5/8” burst is 6890 psi / 2 = 3445 psi.
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17.16 TOH with the drilling assy, standing back drill pipe.
17.17 LD BHA
17.18 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
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18.0 Run 4-1/2”Production Liner
18.1. R/U Weatherford 4-1/2”casing running equipment.
x Ensure 4-1/2”DWC/C-HT 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.
18.2. P/U shoe joint, visually verify no debris inside joint.
18.3. 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
18.4. Continue running 4-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
x 2 Joints with RA tags will be placed to better identify the Beluga for post-rig work. Geo and
Ops engineer will communicate the depths for these joints.
18.5. Continue running 4-1/2” production liner
4-1/2”12.6 DWC/C-HT M/U torques
Casing OD Minimum Maximum Yield Torque
4-1/2”5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs
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18.6. Run in hole w/ 4-1/2” liner to the 7-5/8” casing shoe.
18.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
18.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
18.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
18.10. 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.
18.11. Set casing slowly in and out of slips.
18.12. PU 4-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
18.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
18.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
18.15. 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.
18.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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19.0 Cement 4-1/2”Production Liner
19.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
19.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
19.3. Pump 5 bbls spacer.
19.4. Test surface cmt lines to 4500 psi.
19.5. Pump remaining spacer.
19.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” liner
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
6-3/4” OH x 4-1/2” annulus:
(7083’ –2789’) x .02459 bpf x
1.4 =
147.82 830.0
Total LEAD:158.32 bbl 889.0 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(7583’- 7083’) x .02459 bpf x
1.4 =
17.21 96.6
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf =1.22 6.8
Total TAIL:18.43 bbl 103.4 ft3
TOTAL CEMENT VOL:176.75 bbl 992.4 ft3
Verified cement calcs. -bjm
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Cement Slurry Design:
19.7. 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.
19.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
19.9. If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
19.10. 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.
19.11. Slack off total liner weight plus 30k to confirm hanger is set.
19.12. Do not overdisplace by more than ½ shoe track. Shoe track volume is 2 bbls.
19.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
19.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
Lead Slurry (7083’ MD to 2587’ MD)Tail Slurry (7583’ to 7083’ 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 Concentration Code Description Concentration
G Cement 94#/sk A Cement 94#/sk
D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC
D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC
D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC
D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC
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19.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
19.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
19.17. 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).
19.18. 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.
19.19. 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.
19.20. 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:
19.21. 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.
19.22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
19.23. 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.
19.24. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes.
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Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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20.0 4-1/2”Liner Tieback Polish Run and Cleanout Run
20.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
20.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
20.3. CBU and displace well to 6% KCl completion fluid.
20.4. POOH, and LD polish mill.
20.5. Round trip and LD remaining drillpipe from derrick.
20.6. If not completed, test 4-1/2” casing to 3,000 psi and chart for 30 minutes
21.0 4-1/2” Tieback Run
21.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 DWC/C-HT casing.
21.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
21.3 PU hanger and land string in hanger bowl. Note distance of seals from no-go.
21.4 Install packoff and test hanger void.
21.5 Test 4-1/2” liner and tieback to 3,000 psi and chart for 30 minutes.
21.6 Test 7-5/8” x 4-1/2” annulus to 2,500 psi and chart for 30 minutes.
22.0 RDMO
22.1. Install BPV in wellhead
22.2. N/D BOPE
22.3. N/U dry hole tree or full tree (if available).
22.4. RDMO Hilcorp Rig #169
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23.0 Diverter Schematic
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24.0 BOP Schematic
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25.0 Current Wellhead Schematic
Casing head, Shaffer
KD, 13 5/8 3M X 11 3/4
SOW, w/ 2- 2'’ LPO
Swanson River
SRU 23-33
Proposed-post Rig 401
11 ¾’’
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26.0 Wellhead Schematic
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27.0 Days Vs Depth
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28.0 Geo-Prog
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29.0 Anticipated Drilling Hazards
9-7/8”Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 –45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Losses not experienced in SRU 241-33B in 2021. However, ensure all LCM inventory is fully stocked
before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
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30.0 Hilcorp Rig 169 Layout
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31.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
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32.0 Choke Manifold Schematic
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33.0 Casing Design Information
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34.0 6-3/4” Hole Section MASP
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35.0 Spider Plot (Governmental Sections)
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36.0 660’ Radius for SSSV
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37.0 Surface Plat (As-Built NAD27 & NAD83)
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!!"
#
0
475
950
1425
1900
2375
2850
3325
3800
4275
4750
5225
5700
6175
6650
7125True Vertical Depth (950 usft/in)-475 0 475 950 1425 1900 2375 2850 3325 3800 4275 4750 5225 5700 6175
Vertical Section at 36.00° (950 usft/in)
SRU 231-33 Tyonek tgt1
SRU 231-33 TD tgt
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
SRU 23-33
11 3/4" KOP
7 5/8" X 9 7/8"
4 1/2" X 6 3/4"
500
1000
1 5 0 0
2 0 0 0
25003000350040004500500055006 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
7 5 8 3
SRU 231-33 wp04
KOP: 9.5º/100' : 1000' MD, 999.99'TVD : 0° RT TF
Start Dir 3º/100' : 1020' MD, 1019.99'TVD
End Dir : 2369.46' MD, 2246.91' TVD
Start Dir 2º/100' : 5325.86' MD, 4442.51'TVD
End Dir : 6075.27' MD, 5056.23' TVD
Total Depth : 7583.34' MD, 6392.2' TVD
ST_A14
ST_A15
ST_B3
ST_B5
LB_51-2
LB_51-3
LB_51-7
LB_52-9
TY_54-5
TY_56-9
TY_62-5
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: SRU 23-33
139.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2462919.592 344086.850 60° 44' 18.8669 N 150° 52' 16.3811 W
SURVEY PROGRAM
Date: 2023-01-24T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
220.00 1000.00 Survey #1 (SRU 23-33) 3_INC-Only
1000.00 1400.00 SRU 231-33 wp04 (SRU 231-33) 3_MWD_Interp Azi+Sag
1400.00 2787.00 SRU 231-33 wp04 (SRU 231-33) 3_MWD+IFR1+MS+Sag
2787.00 7583.34 SRU 231-33 wp04 (SRU 231-33) 3_MWD+IFR1+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
2625.00 2471.00 2878.61 ST_A14
2680.00 2526.00 2952.67 ST_A15
2903.00 2749.00 3252.94 ST_B3
2957.00 2803.00 3325.65 ST_B5
4964.00 4810.00 5970.22 LB_51-2
5014.00 4860.00 6027.44 LB_51-3
5162.00 5008.00 6194.71 LB_51-7
5209.00 5055.00 6247.76 LB_52-9
5404.00 5250.00 6467.88 TY_54-5
5624.00 5470.00 6716.22 TY_56-9
6208.00 6054.00 7375.46 TY_62-5
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well SRU 23-33, True North
Vertical (TVD) Reference:RKB @ 154.00usft
Measured Depth Reference:RKB @ 154.00usft
Calculation Method:Minimum Curvature
Project:Swanson River Unit
Site:SRU 23-33
Well:SRU 23-33
Wellbore:SRU 231-33
Design:SRU 231-33 wp04
CASING DETAILS
TVD TVDSS MD Size Name
999.95 845.95 1000.00 11-3/4 11 3/4" KOP
2557.00 2403.00 2787.05 7-5/8 7 5/8" X 9 7/8"
6392.16 6238.16 7583.34 4-1/2 4 1/2" X 6 3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 1000.00 0.00 0.00 999.99 0.00 0.00 0.00 0.00 0.00 KOP: 9.5º/100' : 1000' MD, 999.99'TVD : 0° RT TF
2 1020.00 1.90 0.00 1019.99 0.33 0.00 9.50 0.00 0.27 Start Dir 3º/100' : 1020' MD, 1019.99'TVD
3 2369.46 42.04 34.31 2246.91 413.27 265.82 3.00 35.55 490.58 End Dir : 2369.46' MD, 2246.91' TVD
4 5325.86 42.04 34.31 4442.51 2048.67 1381.67 0.00 0.00 2469.53 Start Dir 2º/100' : 5325.86' MD, 4442.51'TVD
5 6075.27 27.64 41.72 5056.23 2387.63 1640.27 2.00 166.61 2895.75 End Dir : 6075.27' MD, 5056.23' TVD
6 6750.27 27.64 41.72 5654.20 2621.35 1848.68 0.00 0.00 3207.34 SRU 231-33 Tyonek tgt1
7 7583.34 27.64 41.72 6392.20 2909.81 2105.89 0.00 0.00 3591.90 SRU 231-33 TD tgt Total Depth : 7583.34' MD, 6392.2' TVD
0
175
350
525
700
875
1050
1225
1400
1575
1750
1925
2100
2275
2450
2625
2800
2975
3150
3325
South(-)/North(+) (350 usft/in)-175 0 175 350 525 700 875 1050 1225 1400 1575 1750 1925 2100 2275
West(-)/East(+) (350 usft/in)
SRU 231-33 TD tgt
SRU 231-33 Tyonek tgt1
SRU 23-33
11 3/4" KOP
7 5/8" X 9 7/8"
4 1/2" X 6 3/4"
25050075010001250
1500
1750
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KOP: 9.5º/100' : 1000' MD, 999.99'TVD : 0° RT TF
Start Dir 3º/100' : 1020' MD, 1019.99'TVD
End Dir : 2369.46' MD, 2246.91' TVD
Start Dir 2º/100' : 5325.86' MD, 4442.51'TVD
End Dir : 6075.27' MD, 5056.23' TVD
Total Depth : 7583.34' MD, 6392.2' TVD
CASING DETAILS
TVD TVDSS MD Size Name
999.95 845.95 1000.00 11-3/4 11 3/4" KOP
2557.00 2403.00 2787.05 7-5/8 7 5/8" X 9 7/8"
6392.16 6238.16 7583.34 4-1/2 4 1/2" X 6 3/4"
Project: Swanson River Unit
Site: SRU 23-33
Well: SRU 23-33
Wellbore: SRU 231-33
Plan: SRU 231-33 wp04
WELL DETAILS: SRU 23-33
139.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2462919.592 344086.850 60° 44' 18.8669 N 150° 52' 16.3811 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well SRU 23-33, True North
Vertical (TVD) Reference: RKB @ 154.00usft
Measured Depth Reference:RKB @ 154.00usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500 7875 8250Measured Depth (750 usft/in)SRU 23-33SRU 14A-33SRU 41-33No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS: SRU 23-33 NAD 1927 (NADCON CONUS) Alaska Zone 04139.00+N/-S+E/-W NorthingEastingLatitudeLongitude0.000.00 2462919.592344086.85060° 44' 18.8669 N 150° 52' 16.3811 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well SRU 23-33, True NorthVertical (TVD) Reference:RKB @ 154.00usftMeasured Depth Reference:RKB @ 154.00usftCalculation Method:Minimum CurvatureCASING DETAILSTVD TVDSS MD Size Name999.95 845.95 1000.00 11-3/4 11 3/4" KOP2557.00 2403.00 2787.05 7-5/8 7 5/8" X 9 7/8"6392.16 6238.16 7583.34 4-1/2 4 1/2" X 6 3/4"SURVEY PROGRAMDate: 2023-01-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool220.00 1000.00 Survey #1 (SRU 23-33) 3_INC-Only1000.00 1400.00 SRU 231-33 wp04 (SRU 231-33) 3_MWD_Interp Azi+Sag1400.00 2787.00 SRU 231-33 wp04 (SRU 231-33) 3_MWD+IFR1+MS+Sag2787.00 7583.34 SRU 231-33 wp04 (SRU 231-33) 3_MWD+IFR1+MS+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation (80.00 usft/in)1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125 7500 7875 8250Measured Depth (750 usft/in)SRU 23-33SRU 23-33SRU 14A-33GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference1000.00 To 7583.34Project: Swanson River UnitSite: SRU 23-33Well: SRU 23-33Wellbore: SRU 231-33Plan: SRU 231-33 wp04Ladder/S.F. Plots
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
Swanson River
SRU 231-33
223-008
Sterling/Upper Beluga, Beluga, and Tyonek Gas Pools
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:SWANSON RIV UNIT 231-33Initial Class/TypeDEV / PENDGeoArea820Unit51994On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230080SWANSON RIVER, TYONEK GAS - 772500 SWANSON RIVER, BELUGA GSWANSON RIVER, STRLG/U BLUG GS - 77255NA1 Permit fee attachedYes Entire Well lies within ADL0028399.2 Lease number appropriateYes3 Unique well name and numberYes Sterling/Upper Beluga, Beluga, and Tyonek Gas Pools - governed by CO 716A4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes30 BOPE press rating appropriate; test to (put psig in comments)Yes MPSP = 2237. BOP rated to 5K. (BOP test to 3000 psi)31 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 is not reported from Swanson River Field and is not expected based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Abnormal pressure not expected based on nearby wells. Proposed mud program appears36 Data presented on potential overpressure zonesNA sufficient to control the operator's forecast of expected formation pressures. Additional37 Seismic analysis of shallow gas zonesNA materials will be onsite to raise mud weight to 1 ppg above highest anticipated mud weight.38 Seabed condition survey (if off-shore)NA Well will be mud logged. Lost circulation supplies will be available onsite.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate2/9/2023ApprBJMDate2/9/2023ApprSFDDate2/9/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 2/10/2023
