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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/28/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240528
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 5/13/2024 AK E-LINE CIBP/Cement
HV B-12 50231200310000 207123 4/26/2024 AK E-LINE PPROF
HV B-16A 50231200400100 222070 4/24/2024 AK E-LINE PPROF
HV B-17 50231200490000 215189 4/23/2024 AK E-LINE Perf
KTU 43-6XRD2 50133203280200 205117 5/10/2024 AK E-LINE Perf
LRU C-02 50283201900000 223057 5/8/2024 AK E-LINE Perf
MPU C-11A 50029213210100 221001 2/17/2024 AK E-LINE SetPacker
NCIU A-17 50883201880000 223031 4/13/2024 AK E-LINE Plug/Perf/GPT
Please include current contact information if different from above.
T38851
T38852
T38853
T38854
T38855
T38856
T38857
T38858
LRU C-02 50283201900000 223057 5/8/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.29 09:23:53 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
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 7,501 feet See Schematic feet
true vertical 7,061 feet N/A feet
Effective Depth measured 6,078 feet 2,963 feet
true vertical 5,659 feet 2,642 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 3,012' MD 2,684' TVD
Packers and SSSV (type, measured and true vertical depth)BHL Ret Pkr; N/A 2,963' MD 2,642' TVD N/A, N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date:Contact Name:
Contact Email:
Authorized Title:Contact Phone:
Jake Flora, Operations Engineer
324-193
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
1442
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
jake.flora@hilcorp.com
907-777-8442
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
144
Size
120'
0 2003137
0 7900
1038
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-057
50-283-20190-00-00
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Hilcorp Alaska, LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL 058798
Lewis River / Lewis River Undefined Gas
Lewis River Unit (LRU) C-02
Plugs
Junk measured
Length
Production
Liner
4,336'
Casing
Structural
6,905'7,341'
120'Conductor
Surface
Intermediate
16"
9-5/8"
120'
3,187'
7,500psi
2,980psi
6,870psi
8,430psi
3,187'2,838'
Burst Collapse
1,410psi
4,760psi
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
Noel Nocas
(4361)
Digitally signed by
Noel Nocas (4361)
Date: 2024.05.16
15:33:12 -08'00'
By Grace Christianson at 3:59 pm, May 16, 2024
DSR-5/20/24
RBDMS JSB 052824
Well Name: LRU C-002
API #:50-283-20190-00-00 Field:Lewis River Start Date:4/28/2024
Permit #:223-057 Sundry #:324-193 End Date:5/9/2024
4/28/2024
4/29/2024
5/8/2024
5/9/2024
Daily Operations:
Activity Report
Fly AK E-Line to Beluga, gather equipment, travel to location, PTW & PJSM. RU and PT lubricator 250/2500 psi. Perforate, with well
flowing, BEL_I 9 (4813'-4822'), BEL_I 8 (4722'-4738') and BEL_I 4 (4622'-4638').
AKE-line PTW & PJSM, travel to location. Rig back on well, FTP-776 psi / 1400 mcfd. Resume perforating the BEL_I4 sand (4611'-4618'),
BEL_I sand (4427'-4438') and BEL_H11 sand (4112'-4134'). Significant pressure and rate increase witnessed after shooting upper H11
(4112'-4124'). Final 1275 psi / 2950 mcfd. Secure well and turn over to production. RDMO E-line, job complete. Return crew back to Kenai.
AK E-line PTW, PJSM and travel to location. Complete rig up on well, M/U GR/CCL and gun #1,
PT 250psi/2500 psi. Pass. FTP-755 psi. / 1338 mcfd. RIH and tag PBTD at 6067' (CIBP-6078') correlated and perforated the J4 sand (5357'-
5371'). Continued perforating the J4 (5258'-5270'), J3 (5189'-5194') and J2 sand (5142'-5147'). Secure well. Rigged back & SDFN. FTP-765
psi / 1384 mcfd.
AK E-line PTW, PJSM, travel to location. Rig back on well and continue perforating with well flowing. FTP - 775 psi / 1360 mcfd. Perforate
two J2 sands (5126'-5129') and (5134'-5139') with switch guns. RIH with second run and perforate J sand (5038'-5050'). FTP - 767 psi.
Secure well and RDMO E-line. Job complete return crew to Kenai and hand well over to production to flow test add perfs.
Page 1 of 1
Updated by DMA 05-16-24
SCHEMATIC
Lewis River Unit
LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
PBTD = 7,275’ MD / TVD = 6,840’
TD = 7,501 MD / TVD = 7,061’
RKB to GL = 18.5’
T13
T12
T8A – T11
T7
Bel I – Bel J
T6
Bel H
Bel I
Bel J
T5
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 80'
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 3,187’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 3,005’ 7,341’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 3,012’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,505’ 3.958” 4.500 Chemical Injection Sub
2 2,963’ 3.980” 8.250” 9-5/8” x 4-1/2” BHL Ret Packer
3 3,005’ 6.151” 8.540” Liner hanger / LTP Assembly
4 3,010’ 3.813” 5.000’ X Nipple
5 3,011’ 3.920” 5.250” WLEG
6 6,078’ - 3.710” CIBP
7 6,220’ - 3.710” CIBP
8 6,320’ - 3.710” CIBP
9 6,699’ - 3.710” CiBP
10 6,760’ - 3.710” CIBP
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface 1022 sx
4-1/2” TOC @ ~3,180’ MD (CBL) Pumped 1026 sx
8-1/2”
hole
4/5
2
3
PERFORATION DETAIL
Zone Top MD Btm MD Top TVD Btm TVD FT Date Size Status
Bel H11 4,112' 4,134' 3,719' 3,839' 22’ 5/9/2024 2-3/4” 6 Open
Bel H11 4,427' 4,438' 4,029' 4,040' 11’ 5/9/2024 2-3/4” 6 Open
Bel I 4,611' 4,618' 4,211' 4,218' 7’ 5/9/2024 2-3/4” 6 Open
Bel I4 4,622' 4,538' 4,222' 4,139' 16’ 5/8/2024 2-3/4” 6 Open
Bel I4 4,722' 4,738' 4,321' 4,336' 16’ 5/8/2024 2-3/4” 6 Open
Bel I8 4,754’ 4,766’ 4,353’ 4,365’ 12’ 9/29/2023 2-3/8” 6 Open
Bel I8 4,758’ 4,798’ 4,376’ 4,395’ 20’ 9/30/2023 2-3/8” 6 Open
Bel I9 4,813’ 4,822’ 4,410' 4,419' 9’ 5/8/2023 2-3/4” 6 Open
Bel I12 4,924’ 4,934’ 4,520’ 4,530’ 10’ 9/29/2023 2-3/8” 6 Open
Bel J1 4,984’ 4,994’ 4,579’ 4,589’ 10’ 9/29/2023 2-3/8” 6 Open
Bel J2 5,126' 5,129' 4,721' 4,724' 3’ 4/29/2024 2-3/4” 6SPF Open
Bel J2 5,134' 5,139' 4,729' 4,733' 5’ 4/29/2024 2-3/4” 6SPF Open
Bel J2 5,142' 5,147' 4,736' 4,741' 5’ 4/28/2024 2-3/4” 6SPF Open
Bel J3 5,189' 5,194' 4,783' 4,788' 5’ 4/28/2024 2-3/4” 6SPF Open
Bel J4 5,258' 5,270' 4,851' 4,863' 12’ 4/28/2024 2-3/4” 6SPF Open
Bel J4 5,300’ 5,320’ 4,891’ 4,910’ 20’ 9/28/2023 2-3/8” 6 Open
Bel J4 5,357' 5,371' 4,949' 4,962' 14’ 4/28/2024 2-3/4” 6SPF Open
Bel J6 5,564’ 5,584’ 5,151’ 5,171’ 20’ 9/28/2023 2-3/8” 6 Open
T5 6,005’ 6,015’ 5,585’ 5,595’ 10’ 9/25/2023 2-3/4” 6 Open
T6 6,103’ 6,122’ 5,684’ 5,703’ 19’ 9/21/2023 2-3/4” 6 Isolated
T6 6,152’ 6,166’ 5,732’ 5,746’ 14’ 9/20/2023 2-3/4” 6 Isolated
T6 6,188’ 6,201’ 5,768’ 5,781’ 13’ 9/20/2023 2-3/4” 6 Isolated
T7 6,240’ 6,246’ 5,818’ 5,824’ 6’ 9/19/2023 2-3/4” 6 Isolated
T7 6,249’ 6,258’ 5,827’ 5,836’ 9’ 9/19/2023 2-3/4” 6 Isolated
T8A 6,338’ 6,356’ 5,916’ 5,934’ 18’ 9/18/2023 2-3/4” 6 Isolated
T11 6,563’ 6,576’ 6,137’ 6,150’ 13’ 9/17/2023 2-3/4” 6 Isolated
T11 6,586’ 6,595’ 6,160’ 6,169’ 9’ 9/17/2023 2-3/4” 6 Isolated
T12 6,724’ 6,757’ 6,296’ 6,328’ 33’ 9/16/2023 2-3/4” 6 Isolated
T13 6,763’ 6,777’ 6,332’ 6,346’ 14’ 9/15/2023 2-3/4” 6 Isolated
T13 6,795’ 6,800’ 6,366’ 6,371’ 5’ 9/15/2023 2-3/4” 6 Isolated
T13 6,806’ 6,820’ 6,380’ 6,394’ 14' 9/15/2023 2-3/4” 6 Isolated
6
7
8
9
10
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: 5/10/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240510-1
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 242-04 50283201640000 212041 3/11/2024 AK E-LINE Perf
LRU C-01RD 50283200610100 201168 4/26/2024 AK E-LINE Perf
LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf
MPU F-65 50029227526000 223121 5/3/2024 AK E-LINE HoistCut
MPU L-07 50029220280000 190037 4/26/2024 AK E-LINE Perf
NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf
NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF
NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF
PAXTON 6 50133207070000 222054 4/13/2024 AK E-LINE GPT/CIBP/Perf
PAXTON 6 50133207070000 222054 4/16/2024 AK E-LINE GPT/CIBP/Perf
SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper
SRU 32C-15 50133206130000 213070 4/24/2024 AK E-LINE Caliper
TBU M-15 50733204220000 190109 4/18/2024 AK E-LINE GPT/Puncher
TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL
Please include current contact information if different from above.
T38780
T38781
T38782
T38783
T38784
T38785
T38786
T38786
T38787
T38787
T38788
T38789
T38790
T38791
LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.05.13 15:31:19 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name: 4.Current Well Class: 5.Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7.If perforating:8.Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,501'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,760psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16.Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
BHL Ret Pkr; N/A 2,963'MD/2,642'TVD; N/A
7,061' 6,078' 5,659'
Lewis River Lewis River Undefined Gas
16"
9-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Lewis River Unit (LRU) C-02Statewide Spacing
Same
6,905'4-1/2"
~1650psi
4,336'
See Schematic
Length
April 15, 2024
Tieback 4-1/2"
7,341'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,870psi
120'120'
3,187"
Size
120'
3,187'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
3,012'
8,430psi
2,838'
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
ADL 058798
223-057
50-283-20190-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
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 8:36 am, Apr 02, 2024
324-193
gov
10-404
SFD 4/3/2024BJM 4/11/24
Dump bail 25' of cement on CIBP at 6078' MD prior to adding perfs.
DSR-4/12/24JLC 4/12/2024
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.04.12 14:16:46
-08'00'04/12/24
RBDMS JSB 042624
Shallowest allowable perf calcs must be based on deepest perfs until they have been isolated with cement per 20 AAC 25.112.
Dump bail 25' of cement on CIBP to P&A lower perfs before adding new perfs. -bjm
Updated by DMA 04-01-24
PROPOSED
Lewis River Unit
LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
PBTD = 7,275’ MD / TVD = 6,840’
TD = 7,501 MD / TVD = 7,061’
RKB to GL = 18.5’
T13
T12
T8A – T11
T7
T5
Bel I
Bel J
Bel G
Bel H
T6
B
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 80'
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 3,187’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 3,005’ 7,341’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 3,012’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,505’ 3.958” 4.500 Chemical Injection Sub
2 2,963’ 3.980” 8.250” 9-5/8” x 4-1/2” BHL Ret Packer
3 3,005’ 6.151” 8.540” Liner hanger / LTP Assembly
4 3,010’ 3.813” 5.000’ X Nipple
5 3,011’ 3.920” 5.250” WLEG
6 6,078’ - 3.710” CIBP
7 6,220’ - 3.710” CIBP
8 6,320’ - 3.710” CIBP
9 6,699’ - 3.710” CIBP
10 6,760’ - 3.710” CIBP
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface 1022 sx
4-1/2” TOC @ ~3,180’ MD (CBL) Pumped 1026 sx
8-1/2”
hole
4/5
2
3
PERFORATION DETAIL
Zone Top MD Btm MD Top TVD Btm TVD FT Date Size Status
Bel G-J ±3,622’ ±5,371’ ±3,237’ ±4,962’ ±1,749’ Proposed 2-3/8” 6 SPF TBD
Bel I8 4,754’ 4,766’ 4,353’ 4,365’ 12’ 9/29/23 2-3/8” 6 SPF Open
Bel I8 4,758’ 4,798’ 4,376’ 4,395’ 20’ 9/30/23 2-3/8” 6 SPF Open
Bel I12 4,924’ 4,934’ 4,520’ 4,530’ 10’ 9/29/23 2-3/8” 6 SPF Open
Bel J1 4,984’ 4,994’ 4,579’ 4,589’ 10’ 9/29/23 2-3/8” 6 SPF Open
Bel J4 5,300’ 5,320’ 4,891’ 4,910’ 20’ 9/28/23 2-3/8” 6 SPF Open
Bel J6 5,564’ 5,584’ 5,151’ 5,171’ 20’ 9/28/23 2-3/8” 6 SPF Open
T5 6,005’ 6,015’ 5,585’ 5,595’ 10’ 9/25/23 2-3/4” 6 SPF Open
T6 6,103’ 6,122’ 5,684’ 5,703’ 19’ 9/21/23 2-3/4” 6 SPF Isolated
T6 6,152’ 6,166’ 5,732’ 5,746’ 14’ 9/20/23 2-3/4” 6 SPF Isolated
T6 6,188’ 6,201’ 5,768’ 5,781’ 13’ 9/20/23 2-3/4” 6 SPF Isolated
T7 6,240’ 6,246’ 5,818’ 5,824’ 6’ 9/19/23 2-3/4” 6 SPF Isolated
T7 6,249’ 6,258’ 5,827’ 5,836’ 9’ 9/19/23 2-3/4” 6 SPF Isolated
T8A 6,338’ 6,356’ 5,916’ 5,934’ 18’ 9/18/23 2-3/4” 6 SPF Isolated
T11 6,563’ 6,576’ 6,137’ 6,150’ 13’ 9/17/23 2-3/4” 6 SPF Isolated
T11 6,586’ 6,595’ 6,160’ 6,169’ 9’ 9/17/23 2-3/4” 6 SPF Isolated
T12 6,724’ 6,757’ 6,296’ 6,328’ 33’ 9/16/23 2-3/4” 6 SPF Isolated
T13 6,763’ 6,777’ 6,332’ 6,346’ 14’ 9/15/23 2-3/4” 6 SPF Isolated
T13 6,795’ 6,800’ 6,366’ 6,371’ 5’ 9/15/23 2-3/4” 6 SPF Isolated
T13 6,806’ 6,820’ 6,380’ 6,394’ 14' 9/15/23 2-3/4” 6 SPF Isolated
6
7
8
9
10
Hilmrpai;uska_ LLU
Date: 11/ 16/2023
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503 l
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
Washed and Dried Well Samples (08/21/2023)
B Set (5 Boxes):
RECEIVED
MEN:, s '41 16 2023
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
LRU C-02
BOX 1 OF 5
138' - 1500' MD
LRU C-02
BOX 2 OF 5
1500' - 3000' MD
LRU C-02
BOX 3 OF 5
3000' - 4500' MD
LRU C-02
BOX 4 OF 5
4500' - 6090' MD
LRU C-02
BOX 5 OF 5
6090' - 7501' MD
Please include current contact information if different from above.
Nab �.A®GCC
A®GCC
Please acknowledge receip�by--signing and returning one copy of this transmittal.
Received Oy. / Date:
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231025
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 241-23 50283201910000 223061 9/27/2023 AK E-LINE CBL
BRU 241-23 50283201910000 223061 10/4/2023 AK E-LINE GPT/Plug/Perf
GP ST 18742 37 50733203940000 187109 9/30/2023 AK E-LINE Plug
IRU 41-01 50283200880000 192109 9/22/2023 AK E-LINE Perf/GPT
LRU C-02 50283201900000 223057 9/28/2023 AK E-LINE Perf
LRU C-02 50283201900000 223057 9/25/2023 AK E-LINE Perf/GPT
MPU K-13 50029226550000 196040 10/1/2023 AK E-LINE GPT/Plug/Perf
NCI A-05 50883200250000 169032 9/27/2023 AK E-LINE Perf
Please include current contact information if different from above.
T38097
T38097
T38098
T38099
T38100
T38100
T38101
T38102
10/25/2023
LRU C-02 50283201900000 223057 9/28/2023 AK E-LINE Perf
LRU C-02 50283201900000 223057 9/25/2023 AK E-LINE Perf/GPT
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.10.25
11:33:48 -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): Lewis River Unit
GL: 103.4' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" X-56 120'
9-5/8" L-80 2,838'
4-1/2" L-80 6,905'
4-1/2" L-80 2,684'
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:
011009 190
10/7/2023 24
Flow Tubing
1
2030
N/A20300
511' FSL, 2021' FWL, Sec 35, T15N, R9W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
3,012'
2,678'
Surface
84#
47#
120'
Water-Bbl:
PRODUCTION TEST
9/29/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
351878
352322
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)
Conductor
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2683355
SETTING DEPTH TVD
2683255
TOP HOLE SIZE
CBL 9-13-23, Mudlogs, GPT, Perf Correlation, LWD (AGR, PWD, DDSR, EWR-M5, CTN, ALD, DDSR)
N/A
N/A
N/A
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
350275 2683741
50-283-20190-00-00July 31, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
9/15/2023 223-057 / 323-482
LOCI 89-28
LRU C-02August 20, 2023970' FSL, 32' FEL, Sec 34, T15N, R9W, SM, AK
121.9'
Lewis River Undefined Gas Pool
ADL 58798
7,501' MD / 7,061' TVD
7,275' MD / 6,840' TVD
606' FSL, 1576' FWL, Sec 35, T15N, 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,
Tieback Assy.Tieback
TUBING RECORD
L - 845 sx / T - 181 sx8-1/2"
12-1/4"
Driven
Surface L - 708 sx / T - 314 sx
12.6#
Surface
4-1/2"
SIZE DEPTH SET (MD)
2,963' / 2,642'
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
3,005' 7,341'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
3,012'
Surface
3,187'
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 3:57 pm, Oct 16, 2023
Completed
9/15/2023
JSB
RBDMS JSB 101723
GDSR-11/15/23BJM 01/09/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval Bel I 4,754' 4,353'
2905' 2588'
3029' 2700'
3224' 2870'
3456' 3079'
3851' 3462'
4317' 3921'
4972' 4567'
5656' 5242'
5976' 5558'
6103' 5683
6202' 5781'
6564' 6138'
T16
7175' 6741'
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:
T6
T7
T11
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
T5
Bel G
Bel D
Bel H
T1
Bel E
Bel F
Bel I
Bel J
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
Drilling Manager
10/16/23
Monty M
Myers
Updated by CJD 10/16/2023
SCHEMATIC
Lewis River Unit
LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
PBTD = 7,275’ MD / TVD = 6,840’
TD = 7,501 MD / TVD = 7,061’
RKB to GL = 18.5’
T13
T12
T8A – T11
T7
Bel I – Bel J
T6
Bel I – T5
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 80'
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 3,187’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 3,005’ 7,341’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 3,012’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,505’ 3.958” 4.500 Chemical Injection Sub
2 2,963’ 3.980” 8.250” 9-5/8” x 4-1/2” BHL Ret Packer
3 3,005’ 6.151” 8.540” Liner hanger / LTP Assembly
4 3,010’ 3.813” 5.000’ X Nipple
5 3,011’ 3.920” 5.250” WLEG
6 6,078’ - 3.710” CIBP
7 6,220’ - 3.710” CIBP
8 6,320’ - 3.710” CIBP
9 6,699’ - 3.710” CiBP
10 6,760’ - 3.710” CIBP
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface 1022 sx
4-1/2” TOC @ ~3,180’ MD (CBL) Pumped 1026 sx
8-1/2”
hole
4/5
2
3
PERFORATION DETAIL
Zone Top
(MD)
Btm
(MD)
Top
(TVD)
Btm
(TVD) FT Date Size Status
Bel I 4,754’ 4,766’ 4,353’ 4,365’ 12’ 9/29/23 2-3/8” 6 SPF Open
Bel I 4,778’ 4,798’ 4,376’ 4,395’ 20’ 9/30/23 2-3/8” 6 SPF Open
Bel I 4,924’ 4,934’ 4,520’ 4,530’ 10’ 9/29/23 2-3/8” 6 SPF Open
Bel J 4,984’ 4,994’ 4,579’ 4,589’ 10’ 9/29/23 2-3/8” 6 SPF Open
Bel J 5,300’ 5,320’ 4,891’ 4,910’ 20’ 9/28/23 2-3/8” 6 SPF Open
Bel J 5,564’ 5,584’ 5,151’ 5,171’ 20’ 9/28/23 2-3/8” 6 SPF Open
T5 6,005’ 6,015’ 5,585’ 5,595’ 10’ 9/25/23 2-3/4” 6 SPF Open
T6 6,103’ 6,122’ 5,684’ 5,703’ 19’ 9/21/23 2-3/4” 6 SPF Isolated
T6 6,152’ 6,166’ 5,732’ 5,746’ 14’ 9/20/23 2-3/4” 6 SPF Isolated
T6 6,188’ 6,201’ 5,768’ 5,781’ 13’ 9/20/23 2-3/4” 6 SPF Isolated
T7 6,240’ 6,246’ 5,818’ 5,824’ 6’ 9/19/23 2-3/4” 6 SPF Isolated
T7 6,249’ 6,258’ 5,827’ 5,836’ 9’ 9/19/23 2-3/4” 6 SPF Isolated
T8A 6,338’ 6,356’ 5,916’ 5,934’ 18’ 9/18/23 2-3/4” 6 SPF Isolated
T11 6,563’ 6,576’ 6,137’ 6,150’ 13’ 9/17/23 2-3/4” 6 SPF Isolated
T11 6,586’ 6,595’ 6,160’ 6,169’ 9’ 9/17/23 2-3/4” 6 SPF Isolated
T12 6,724’ 6,757’ 6,296’ 6,328’ 33’ 9/16/23 2-3/4” 6 SPF Isolated
T13 6,763’ 6,777’ 6,332’ 6,346’ 14’ 9/15/23 2-3/4” 6 SPF Isolated
T13 6,795’ 6,800’ 6,366’ 6,371’ 5’ 9/15/23 2-3/4” 6 SPF Isolated
T13 6,806’ 6,820’ 6,380’ 6,394’ 14' 9/15/23 2-3/4” 6 SPF Isolated
Activity Date Ops Summary
7/25/2023 Wellhead Rep pressure tested BRU 211-35 dryhole tree, hanger void and neck seals at 5000 psi for 10 minutes each, good tests. RD and released wellhead
Rep. Cont RD pits and prep for moving. On E pad, Undressed rig floor, changed topdrive gear box oil and checked end play, removed bails, torque bushing,
service loop and Kelly hose, set topdrive in cradle and un-pinned from blocks, L/D topdrive, cont RD pits and pump skids, installed shipping beams in cellar.
Brought in CCI crane, RU and L/D poorboy degasser, folded back beaver slide, RU and transferred BOP stack from bridge cranes to cradle, L/D cradle.
Inspected and prepped to scope down derrick, held PJSM, scoped down derrick, L/D lower torque tube,. loaded degasser and cuttings box and shipped out.
Unspooled drill line and cut off 66', disconnect all Pason cords, folded up derrick board. Lay over derrick, continue pressure washing around rig, remove
driveline and brake linkage, lower mud tank rooves on tank 2 & 3, unpin derrick cylinders and roll up all cables on derrick, R/D modules, pull electrical lines and
spool up. Lower catwalk slide and R/D, Lower pit roof 1, scope down dog house and disconnect power and remaining lines, disconnect remaining air power and
water lines, pull handy berm from around rig, prep modules for trucks.
7/26/2023 CCI drivers/trucks on location at 06:00, held PJSM with rig team, tore out catwalk and PU rig mats, tore out doghouse skid, gen skid, all three pit modules, 40'
connex and HPU skid, staged all these near airstrip. Staged cranes, RU and picked derrick off carrier. picked carrier off sub base, picked sub base off pony
walls. Loaded mats, pony walls and test pump, started stacking mats on E pad. Transported doghouse, pony walls, cranes, sub, derrick and carrier to Lewis
River. Bed truck carrying carrier blew two tires one mile north of Beluga River bridge. Truck set carrier on road and pulled off at wide spot. Once truck offloaded
pony walls and mats on C pad went back and retrieved carrrier. On C pad, set pony walls, spotted cranes and set subcarrier and derrick. Set doghouse skid and
raised same. Cont stacking all mats on E pad, picked up liner and felt, cont loading misc equipment. Transported mats and iron roughneck to C pad, CCI
returned to BRU airstrip and loaded for return to C pad. Transport Pit modules and pump module to C Pad, Set pit modules jig and pump skid #1, raise pit
rooves, set Iron roughneck on floor, raise derrick to half mast, bring in Pump skid #2, gen skid and top drive HPU, Raise Gas buster and pin, get power going
around rig, R/U modules. Continue R/U modules, mount all lights, transport misc equipment to D pad for staging, spot in centrifuge spot in cuttings tank, spool
drilling line, prep to scope derrick, lay felt and liner for catwalk.
7/27/2023 Transport catwalk, 40' connex and boiler to C pad and spot in, continue R/U Modules, R/D office trailers on E Pad and transport to C Pad, R/D com tower on E
Pad, continue hauling miscellaneous loads to pad and D pad organize location. PJSM, scope up derrick, install T Bar and turn buckles, set office trailers and
change shack, fly in stairs and sewer tanks, power up offices, set in hurricane vac, Staged and P/U top drive off skate, M/U to top drive, P/U torque bushing
hook up service loop and Kelly hose, start Rig Acceptance. @ 1630 hrs CCI hand un binding load from trailer, removed chain holding bucket to loader forks
causing bucket to roll forward onto arms and legs, hands near by helped to free him and he was taken to medic for evaluation, Medic returned him to work.
Function test top drive, continue hooking up kelly hose, work on rig acceptance check list, Function test mix pumps and check rotation on centrifuge, spot in
change house, Dress rig floor tongs and subs, hook up bleeder lines and roll through bleeders on the mud pumps, hook up koomey lines between. sub and
water tank, drop shipping beams, and catch can.( Install Well pump and new pipe on D Pad ready for electrician to wire in). N/U Diverter set spacer spool and
speed head, install diverter T, Hang annular on bridge cranes and clean rig groove, set on T and bolt up, install knife valve and vent line, install riser, install
weighted stands and secure vent pipe, hook up koomey lines to annular and knife valve.
7/28/2023 Cont working rig acceptance checklist, wired in water well on D pad but well runs dry within a couple minutes. Moved meter and gen to Ivan River pad and
started hauling water to rig from there. Serviced koomey nitrogen bottles and replaced schrader valve, leveled sub. Handy Berm on location at 10:30 and
berming rig, Re-located 40' connex from rig footprint to make room for aux fuel tank. Brought in pipe bunk of DP for PU. Witness of diverter test waived by
AOGCC Jim Regg at 09:25 on 7-28-23. Cont Handy Berm rig, start install of Starlink comm system, set aux fuel tank, functioned annular and knife valve,
checked torque on rig tongs and iron roughneck, staged dumpster and cleaned up liner/felt trimmings from berming, cont hauling water from Ivan River. tested
surface lines to topdrive at 2440 psi, dressed shakers, installed ground cables module to module, RU Sperry shack, RU mud lab, comm's up and running.
Accepted rig at 14:00 on 7-28-23. Strap tally and Drift pipe, P/U and rack back 57 stands of DP in derrick, Continue building spud mud. Continue P/U and
racking back DP P/U 28 more stand of DP and 16 more jt of HWDP and rack back in derrick, continue building spud mud, work on EAM/s and general
housekeeping, clean rig floor and cellar.
7/29/2023 Broke ram door bolts loose on BOP stack, load dock with drums within Handy Berm, installed auto drain valves on carrier and pump #1 air tanks, LD sleeve
used in rotary for MU stands, cont pressure washing throughout rig, PU entire location of any debris. Performed diverter function test, draw down test, obtained
measurements for diverter vent line/closest ignition source, tested flow show and gain/loss alarms, replaced worn hyd hoses on topdrive extend rams, removed
C & D dumpster from E pad and emptied at dump, disposed of oily waste at incinerator. strapped last 12 jnts surface casing at H pad, Quadco Rep tested all
audio/visual gas alarms, RU radio antenna's and got comm's to service shacks, cont EAM's, checked and dressed all slips for surface BHA. Changed oil/filters
on camp gen, General maintenance and house keeping continue working on EAM's, Clean Radiators on mud pump engines, C/O oil on degasser, organize
buildings, pressure wash rig modules. Complete PM and Gens 1,2 and 3, continue cleaning and organizing rig, Prep handling equipment for BHA#1, work on air
dryer vent line, continue working on EAM's.
7/30/2023 Transported Sperry tools and casing hanger to C pad, PU racked back jar stand, pulled 2 pipe and pump from water well on D pad, RIH with 1 conduit to bottom
(145') and flushed bottom of well with clean vac truck, LD 1 string, re-ran 2 string and pump (pump at 140'). Ran pump with a noticeable. longer run time before
cavitating. Cont to let water well sit an hour then run/repeat in attempt to get better water influx. Transferred fuel to rig tank, transported waste oil to 3MC yard,
cont incinerating oily waste, cont cleaning and PMs on rig equipment, prep directional tools. for PU, cont cleaning and organizing throughout the rig. Increase
active surface volume (spud mud) from 9 ppg to 9.2 ppg, continue working on housekeeping, build 6% KCL in premix, work with directional drillers to P/U I Star.
M/U istar on racks with CCI loader and rig loader so would be able to handle it on the floor when the time comes to P/U BHA, M/U Bit Motor and Cross over to
HWDP, Tag bottom @ 95' P/U off bottom 10' and continue waiting on barge, Continue Housekeeping and general maintenance.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
LRU C-002
Lewis River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00065 LRU C-02 Drilling
Spud Date:
y
Witness of diverter test waived by gg
AOGCC Jim Regg at
pp
Rig Acceptance
7/31/2023 Cont wait on verification surface cement loaded on barge, change water pump seal on gen #3, cont occasional running of water pump on D pad (still 5 minutes
run time then cavitates), got approval to spud well. Held PJSM/spud meeting with rig team. Displaced well to spud mud. Spudded 12 1/4" hole at 95' and drilled
to 212' at 1K wob, 351 gpm-293 psi, 35 rpm-2850 ft/lbs on bott torque, 102 ft/hr ROP drilling with motor and HWDP. CBU then pulled up hole 3 stands HWDP to
31' with no issue. MU BaseStar collar and scribed, RFO of 315. MU Resistar, Lithostar, 2 I-Star battery subs and TMHOC collar, plugged in and uploaded tools,
loaded sources, shallow pulse tested, PU NM flex DCs then MU stand HWDP. Cont drilling 12 1/4" hole from 212' to 310'. Rot wob 2-5K, 392 gpm-694 psi, 40
rpm-3900 ft/lbs on bott torque, 110 ft/hr ROP. Sliding wob 3-4K, 392 gpm-650 psi, 180 psi diff, 170 to 180 ft/hr ROP. MW 9.2/vis 159, ECD's at 9.4 ppg, BGG 1
unit. Had magnetic. interference on survey at 298'. At 359' had clean survey. Cont drilling surface from 310' to 614' 425 gpm 1021 psi SPP, 40 rpm 6.2k tq on
bottom, WOB 2-9k 159 psi diff ROP 120, 40k PUW 34k SOW 38k ROT. Continue Drilling 12 1/4'' Hole section f/ 614' t/ 922' 455 gpm 1006 psi 60 RPM 6.5k tq
on bottom WOB 2-9k 140 diff ROP 120, PUW 42k SOW 36k ROT 39k Distance from Plan 25' 24' High 3.8' Right.
8/1/2023 Cont drilling 12 1/4" surface from 922' to 1256'. Rot wob 2-10K, 478 gpm-1293 psi, 60 rpm-5900 ft/lbs on bott torque, 60 to 100 ft/hr ROP. Sliding wob 9-10K,
477 gpm-1295 psi, 191 psi diff, 147 ft/hr ROP. MW 9.4/vis 200, ECD's at 9.7, BGG 3 units. Did walk through of rig and service shacks with Fish and Game
Reps, Hilcorp Environmental Coordinator and Drilling Engineer. Cont drilling from 1256' to 1417', Rot wob 2-10K, 515 gpm-1428 psi, 70 rpm-8000 ft/lbs on bott
torque, 108 ft/hr ROP. Sliding wob 9-10K, 516 gpm-1476 psi, 175 psi diff, 116 ft/hr ROP, MW 9.4/vis 172, ECD's at 9.9, BGG 1 unit. CBU twice at 518 gpm-1354
psi, 60 rpm-5700 ft/lbs off bott torque. Obtained on bottom survey, flow check showed slight seepage. Pulled up hole on elevators from 1417' to 363' (jars), up wt
46K, no issues. Calc hole fill = 9.6 bbls, actual hole fill = 12 bbls. Serviced rig and topdrive, cleaned mud pump suction screens. TIH from 363' to 1358', down wt
25K, no issues. Filled pipe, washed/reamed to bottom with no sign of fill, started sweep down drill string, once sweep exited the bit resumed drilling ahead. Calc
displacement = 19.2 bbls, actual = 15.5 bbls. Cont. drilling 12-1/4" surface hole F/1417'-T/1728'. P/U-46K S/O-32K ROT-38K GPM-525 SPP-1425 psi RPM-70
TQ-8.1K WOB-3/5K Diff-74 psi ROP-100 MW-9.5 ppg ECD-9.96 ppg Max gas- 2 units. Sweep back 8 bbls early, w/ a 20% increase in cuttings. Cont. drilling 12-
1/4" surface hole F/1728' to current depth of 1917'. P/U-48K S/O-35K ROT-42K GPM-528 SPP-1570 psi RPM-70 TQ-8.5K WOB-5/13K Diff-116 psi ROP-63 MW-
9.4 ppg ECD-10.1 ppg Max gas- 37 units. Pumped Low-Vis/Low-weight sweep w/ walnut &. condet @ 1903' due to slow ROP and sticky clays at shaker to help
scrub bit/BHA. Distance to well plan: 21' 21' High .6' Right.
8/2/2023 Cont drilling surface from 1917' to 2094'. Rot wob 13K, 525 gpm-1635 psi, 70 rpm-8900 ft/lbs on bott torque, 28 to 100 ft/hr ROP. Sliding wob 8-10K, 537 gpm-
1716 psi, 128 psi diff, 65 ft/hr ROP. MW 9.5/vis 181, ECD's at 10.0 ppg, BGG 13 units, max gas 25 units. Pumped a 20 bbl lo-vis nutplug condet sweep at 1996'
due to low/slow ROP with no noticeable increase in ROP. Cont drilling surface from 2094' to 2344'. Rot wob 3-20K, 540 gpm-1639 psi, 73 rpm-8400 to 9000
ft/lbs on bott torque, 27 to 140 ft/hr ROP. Sliding wob 6-13K, 537 gpm-1806 psi, 213 psi diff, 20-70 ft/hr ROP. MW 9.7/vis 226, ECD's at 10.1 ppg, BGG 13, max
gas 134 units. Made welding repair to centrifuge electric motor mount (CCI took to weld shop at 3MC), had to change swab on pump #2 (circulated and
reciprocated string prior to connection). CBU at 540 gpm-1635 psi, 70 rpm-8 to 10,000 ft/lbs off bott torque. Obtained on bottom survey and flow checked. POOH
on elevators F/2342'-T/1412' w/ no issues. P/U-56K S/O-38K. Cal hole fill- 8.1 bbls Act- 6.3 bbls Diff- 2.2 bbls loss. CBU at 1472'.Had 50% increase in cuttings
at BU. GPM-530 SPP-1452 RPM-80 TQ-6.5K MW- 9.75 ppg ECD- 10.1 ppg Max gas- 73 units. Serviced rig- Greased crown, block, TD, IR, DWKS, wash pipe,
brake linkage, and drive line. Cleaned suction screens on both MP's. Monitored well on TT (static). RIH on elevator F/1472'-T/2280' w/ no issues, washed last
stand to bottom w/ no fill. P/U-44K S/O-34K. Pipe disp.- 15.86 bbls Act- 13.33 bbls Diff- 2..53 bbls loss. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet, at BU
hole unloaded w/ 100% increase in cuttings. Sweep came back on time w/ 10% increase in cuttings. GPM-537 SPP-1607 psi RPM-80 TQ-8.5K MW-9.75 ppg
ECD-10.1 ppg Max gas- 71 units. Cont. directional drilling 12.25" surface hole F/2342'-T/2404'. P/U-62K S/O-40K ROT-50K GPM-530 SPP-1850 psi Flow-38%
RPM-70 TQ-8/10K WOB-15K Diff-200 psi MW-9.75 ppg ECD-10.1 ppg Max gas- 445 units. At 2404' cont. to circ. to allow gas to drop out and. gather cuttings
sample on BU. Coal F/2360'-T/2400'. Crew change, held PTSM. Finished circ. out gas, started dusting MW up to 10.0 ppg. Resumed directional drilling 12.25"
surface hole F/2404', starting our 2 per/100' drop section. At 2527' lost swab on MP #2 pod #3. Isolated MP #2 and changed out swab while circ.&. reciprocating
using MP #1. Cont. drilling ahead to current depth of 2617'. P/U-62K S/O-48K ROT-55K GPM-530 SPP-1677 psi Flow-38% RPM-70 TQ-8/10K WOB-15K Diff-
200 psi MW-9.9 ppg ECD-10.3 ppg Max gas- 232 units. Distance to well plan: 10.94' 10.9' High .1' Left.
8/3/2023 Cont drilling surface from 2617' to 2840', sliding wob 17K, 521 gpm-1750 psi,123 psi diff, 17 to 45 ft/hr ROP. Rot wob 20K, 520 gpm-1849 psi, 77 rpm-8500 ft/lbs
on bott torque, 70 ft/hr ROP. MW 9.9+/vis 202, ECD's at 10.4 ppg, BGG 112 units, max gas 392 units. Cont drilling from 2840' to 2952', sliding wob 19-20K, 533
gpm-1912 psi, 150 psi diff, 20 ft/hr ROP. Rot wob 20-22K, 530 gpm-1818 psi, 80 rpm-7471 ft/lbs on bott torque, 6 to 30 ft/hr ROP. MW 10.0/vis 187, ECD's at
10.4 ppg, BGG 105 units, max gas 1902 units (coal). Pumped lo-vis nutplug condet sweeps at 2883' and 2978' due to low ROP. At 2883' ROP increased
significantly, at 2948' saw no increase in ROP. Cont. directional drilling 12.25" surface hole F/2952'-T/2999'. Pumped Low-Vis sweeps to scrub Bit / BHA of clay
and help w/ ROP as needed. Also added 1 drum of NXS lube to suction pit to increase ROP. P/U-68K S/O-48K ROT-54K GPM-530 SPP-1850 psi RPM-70. TQ-
8/12K WOB-22K Diff-200 psi MW-10.0 ppg ECD-10.3 ppg. AT 2999' notice 300 psi drop in pressure on SPP, hear noise come from discharge side on MP #1.
Shut down MP #1. Racked 1 std back. Cont. working pipe and circ. w/ MP #2. Inspected MP #1, found washed valves and seats on all three pods on MP #1.
After further inspection found pod #1 had washout in body from bottom side. Cleaned up pod#1, brought out welder and worked on patching pod #1 body while
making wiper trip to last trip depth. Flow checked well (static). POOH on elevators F/2916'-T/2341' w/ no issues. While cont. to repair pod #1 on MP #1.P/U-70K
S/O-55K. CBU @ 2342' w/ MP #2. Finished repairs on MP#1 and reassembled pump. GPM-356 SPP-855 Flow 29% TQ-7.1K MW-10 ppg ECD-10.26 ppg.
Serviced rig- Grease crown, block, TD, DWKS, IR, washed pipe, brake linkage, and drive shaft. Cleaned out both MP suction screen. Monitored hole on TT
while servicing rig. Loss rate= 2 bph. Adjusted Kelley hose on TD for correct travel. Function tested MP #1. Cont. hearing noise from pod #1. Resumed working
pipe and circ. w/ MP #2. Tore down pod #1, had destined signs of washing on back side on new seat. POOH on elevators F/2342' while cont. to repair MP #1.
POOH F/2342' P/U-63K S/O-40K. Pulled tight @ 2090' (30K over), attempted to work through on elevators w/ no luck, M/U TD, washed/reamed F/2090'-T/2030'.
POOH on elevators F/2030'-T/1960'. Pulled tight @ 1960' (30K over), attempted to work through on. elevators w/ no luck, M/U TD, washed/reamed F/1960'-
T/1910'. Cont. POOH on elevators F/1910' to current depth of 1230' w/ no issues. Distance to well plan: 7.48' 1.86' Low 7.24' Left.
8/4/2023 Cont to pull up hole on elevators from 1290 to 1230 while installing seat, valve and caps on pod #1, pump #1. At 1230' test ran pump, pod washing around seat
again. Shut down pump and cont pull up hole to 1045'. MU topdrive and CBU at 352 gpm-715 psi, 40 rpm-3300 ft/lbs off bott torque while gathering tools to
remove pod #1. Cont pull up hole from 1045' to jars and parked at 363'. Spotted CCI crane, removed pulsation dampener, popoff assembly, fluid end and pod #1
from pump #1. Had new pod on location at 10:00. Installed pod, fluid end, pulsation dampener and pop off assembly. Installed 5 1/2" liner and swab, cleaned up
tools and primed pump. Test ran pump #1 with no issues CBU at 266 gpm-339 psi, 30 rpm-2092 ft/lbs off bott torque. L/D kelly joint, TIH on elevators from 317'
to 1043', filled pipe and CBU at 511 gpm-1344 psi, 30 rpm-3000 ft/lbs off bott torque, very thick mud but very little cuttings. Cont TIH to 2026', filled pipe and
CBU at 512 gpm-1520 psi, 30 rpm-4932 ft/lbs off bott torque. Hole unloaded prior to bottoms up, mass amount of coal, clay and sand with a max of 54 units gas,
very thick mud. Once shakers cleaned up, TIH to 2964', filled pipe, started a lo-vis nutplug condet sweep down drill string and mad passed from 2964' to 2999'.
Hole unloaded again just prior to bottoms up with a max of 210 units gas. Circulated until shakers cleaned up and mud thinned out. Resumed drilling 12 1/4"
hole F/2999'-T//3106'. P/U-70K S/O-50K ROT-61K wob 25 to 32K, 540 gpm-1950 psi, 40 rpm-6200/10K ft/lbs on bott torque, 6 to 30 ft/hr ROP. (could not get
any diff pressure out of motor at higher rpm's. At 40 rpm could. see 200 psi and ROP better.MW 10.1/vis 169, ECD's at 10.4 ppg, BGG 54 units, max gas-122
units. Crew change, held PTSM. Cont. directional drilling 12.25" surface hole F/3106' to TD of 3195'. Occasionally added 2 sxs of walnut to suction pit to scrub
Bit / BHA of clay and changing drilling parameter to help increase ROP. P/U-65K S/O-52K ROT-58K GPM-533 SPP-1856 psi RPM-70 TQ-9/11K WOB-22/37K
Diff-130 psi MW-10.05 ppg ECD-10.4 ppg Max gas- 264 units. CBU & conditioning mud. Distance to well plan: 8.32' .19' Low 8.32' Left.
p pp(
pudded 12 1/4" hole at 95'
8/5/2023 CBU and built 20 bbl hi-vis nutplug sweep and circulated around at 540 gpm-1692 psi, 85 rpm-6300 ft/lbs off bott torque while dropping vis/conditioning for
casing run and cementing. Max gas 277 units at bottoms up. MW 10.0/vis 80, ECD's at 10.2. Updated AOGCC Jim Regg and Inspectors via email on initial BOP
test timing at 07:41 on 8-5-23. Obtained on bottom survey, flow check = slight seepage. Pulled up hole slow on elevators from 3195' to 2028' with no issue. Up
wt 70K. MU topdrive and CBU at 524 gpm-1427 psi, 40 rpm-4671 ft/lbs off bott torque, max 41 units at bottoms up, very little increase in cuttings. Cont POOH on
elevators from 2028' to BHA at 737'. No issues. Racked back HWDP and jars to 173'. Calc hole fill 25.29 bbls, actual hole fill 32.44 bbls. L/D NM flex DC's, held
PJSM, removed sources, plugged in and downloaded MWD data, L/D TM Hoc, battery subs, lithostar, resistar and base star. Drained motor and L/D. Bit graded
3-5 and in gauge. Cleared and cleaned rig floor and catwalk. C/O elevators, drained stack, PU and dummy ran landing jnt/hanger (22.50'). L/D same. Serviced
rig and topdrive while staging casing equipment on catwalk for PU. RU casing tongs, false table, strap tongs for backups and fill up line. Staged centralizers and
drive sub. Held PJSM with Parker TSM, rig crew and CCI. Inspected and MU shoe track Baker Locking and filling each joint. Checked float equipment (ok). Cont
PU single in hole with 9.625" TXP BTC 47# L-80 surface casing, torqued to 23,820 ft/lbs, inspecting each pin end for flaws or thread cuttings. Filling on the fly,
top filled every 10 jnts. every 10 jnts. P/U-46K S/O-38K. M/U drive sub to stump/TD. Broke circ. Staged up pump, circulated 1-1/2 string volume. P/U-44K S/O-
39K GPM-214 SPP-0 psi MW-10.0 ppg Max gas- 17 units. Cont. P/U and singling in hole with 9.625" TXP BTC 47# L-80 surface casing F/1007'-T/2034'. Run
speed- 15 fpm P/U-76K S/O-62K. M/U drive sub to stump/TD. Broke circ. Staged up pump, circulated 1 string volume. P/U-82K S/O-60K GPM-165 SPP-0 psi
MW-10.0 ppg Max gas- 17 units. Cont. P/U and singling in hole with 9.625" TXP BTC 47# L-80 surface casing F/2034' to current depth of 2922'. Run speed- 15
fpm.
8/6/2023 Cont PU single in hole with 9 5/8" casing from 2922' to 3154', up wt 115K, dwn wt 65K. MU landing joint/hanger, S/O at 72K and landed hanger on landing ring
with no issue. MU circ swedge and topdrive. Broke circ staging up from 75 gpm-152 psi to 135 gpm-66 psi, RD casing tongs and slips, RU bail extensions and
cont to circ and reciprocate while staging cement trucks and equipment. Up wt 100K, dwn wt 80K, max gas 43 units. Spot plug launcher on floor, land string and
shut down circ, removed topdrive and circ swedge. Loaded plugs then MU plug launcher on landing joint. MU circ/cement hose, cont circ at 136 gpm-358 psi
and held PJSM. Shut down rig pump, lined up to pump truck. Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines
at 490 psi low 3533 psi high, good tests. Halliburton pumped 59 bbls 10.5 ppg Tuned Spacer at 5 bpm-500 to 338 psi, dropped bottom plug. and pumped 322
bbls (708 sx) 12 ppg Type I II lead cement at 5 bpm-525 to 254 psi, followed by 62 bbls (314 sx) 15.8 ppg Type I II tail cement at 5 bpm-465 to 439 psi, then 4
bpm-326 psi, then 3 bpm-260 psi. Halliburton dropped top plug then displaced with 10.0 ppg. Spud Mud at 4.9 bpm 216 to 434 psi. Slowed pump to 2.8 bpm with
40 bbl to go. Did bump the plug 228 bbls into displacement (calculated 227.34 bbls). Held 1290 psi (FCP of 850 psi) for 3 minutes, bled off and floats held. Bled
back 1 bbl to truck. Had 60 bbls. of Spacer returns to surface and 131 bbls lead cement to surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix
water temp 58 deg. Pumped 100% excess on lead and tail. Lost 126 bbls throughout the job. Did reciprocate casing. Up wt 130K, dwn wt 58K. upon landing
hanger at start of displacement. 86 bbls into displacement had 11.7 ppg cement to surface. CIP at 12:30 hrs, 8/6/2023. Broke off and blew down cement line to
pump truck, removed plug launcher, drained stack and flushed same with water, B/O and flushed landing joint, L/D same, R/D and released cementers. Cont
blackwater cleanup in pits, cellar box and diverter stack and start RD of vent line. Tore out vent line and anchors, removed knife valve, flow line, flow riser.
Removed annular then "T", spacer spool and adaptor flange in one assembly. Fold back beaver slide, spotted CCI crane, removed annular and "T" assembly
from cellar. Staged wellhead and BOP stack in cellar. Verified with Production orientation of wellhead. Vault WHR installed Cactus wellhead. Pre-tested hanger
neck seals- 5000 psi / 15 min (ok). Locked in wellhead- Post test on neck seals- 5000 psi / 15 min (ok). M/U spacer spool to bottom of BOP stack. Hung flow
box, tailed in BOP stack and set on wellhead w/ bridge cranes. N/U stack to wellhead. Installed bell nipple to annular. M/U koomey HYD lines to stack, M/U
choke & kill lines. Installed flow riser and chained off stack. Opened ram doors, inspected rams and cavities (ok). Finished hauling off spud mud and tank
bottoms to tank farm (pits cleaned). Cont. pulling apart both MP's and inspecting liners, swabs, valves, and seats. Installed rebuilt annular KR valve on koomey.
Crew change, held PTSM. Cont. w/ BOP inspection. Lubricated ram bodies, ram elements, door seals, ran cavities, door bolts, and bolt holes. Buttoned up ram
doors. Re-energized koomey. removed 4" ball valves off conductor. Worked on building 6% KCL PHPA mud. Pulled out and set up DS catwalk racks. Loaded
racks w/ 4.5" DP. Strapped & tallied DP. Obtained RKB's. Changed out annular KR valve on koomey due to failure too rebuilt valve. Set test plug. Function
tested BOP controls and components on 4.5" test jt. Flooded. stack, mud lines, and choke manifold w/ water, purged out air. Currently performing shell test,
cont. to mix new 6% KCL mud, and clean & organize rig.
8/7/2023 Finished shell testing stack and choke manifold, still waiting on word from AOGCC on witness of testing or waived. RD test equipment and pulled test plug.
Installed wear ring, racked and tallied 26 jnts DP. PU singled in then racked back 13 stands, Witness of BOP test was waived by AOGCC Jim Regg at 08:18.
PU test jnt and removed wear ring, set test plug, flooded stack, surface lines and choke manifold, purged air. Tested all BOPE at 250/3500 for 5 min each
(annular at 250/2500) with 4 1/2" test jnt. Performed draw down test, no failures. Removed test plug, set 9" ID wear ring, flooded stack and functioned blinds to
purge air from cavities, purged air from test hose and kill line, closed blinds. pumped 115 gallons to achieve 3582 psi on 9 5/8" casing, held 30 min on chart,
bled back 115 gallons. Lost 23 psi over 30 minutes. Quadco Rep tested audio/visual gas alarms at 14:30. RD test equipment, blew down, lined up stack/choke
manifold for drillout. Went to stage BHA but Sperry had issue with uploading tools on ground (too long to plug in for upload on rig floor), working with support in
Houston. RU Sperry GeoSpan unit in cellar, racked and tallied 20 more jnts DP. PU singled in hole with 20 jnts DP, then racked back same, Sperry tool issue
resolved, staged BHA on catwalk. Held PJSM on P/U BHA. PU 6 3/4" motor with 1.5 bend, MU 8.5" HDBS PDC bit. Measure for off set -133.34 deg. Cont. P/U
MWD tools w/ IDS pressure test collar AKA Geo-Tap tool. Loaded sources. P/U TM collar/stabilizer and flex collars. Shallow pulse tested tools. (ok). Cont. RIH
w/ remainder of BHA out of derrick F/225'-T/785'. P/U-44K S/O-38K. Racked & tallies CDS-40 4.5" DP on catwalk racks. P/U and singled in the hole F/785'-
T/1706'. P/U-50K S/O-44K. Crew change, held PTSM. CBU while strapping & tally DP. P/U-58K S/O-43K GPM-103 SPP-182 psi. Cont. P/U and singled in the
hole F/1706'-T/3013'. P/U-80K S/O-48K. Had calculated pipe displacement for the trip. M/U TD, filled pipe, CBU. P/U-80K S/O-50K GPM-141 SPP-383 psi. Lost
swab on MP #2- pod #3, replaced w/ same. Washed/reamed down F/3013'-T/3080', tagged cmt stringers. Cont. washing/reaming, Tagged TOFC @ 3104',
drilled up plugs, had good indication of hard cmt returns at shaker. drilling out shoe. Currently drilling new formation at 3198'. P/U-80K S/O-50K ROT-60K GPM-
380 SPP-1619 psi RPM-40 TQ-8K Diff-345 psi MW-10 ppg.
8/8/2023 Drilled new formation from 3198 to 3215, Rot wob 5K, 471 gpm-2029 psi, 40 rpm-7000 ft/lbs on bott torque, 32 ft/hr ROP. Sperry having issues with directional
tool comms. CBU at 412 gpm-1199 psiwhile holding PJSM covering displacement to 6% KCL. Pumped 25 bbl hi-vis 10 ppg spacer followed with 10 ppg 6% KCL
mud around, cleaning under shakers and troughs during overboard. With good mud to surface had to reduce rate to. 284 gpm-684 psi. CBU twice, Sperry still
having issue with smart tools. Cycled pumps numerous times with no luck, switched modes with no luck. Shut down pumps and racked back stand to 3166'.
Installed head pin, RU test pump to kill line and drill string. purged air, closed upper rams, pumped 21.25 gallons and achieve d 608 psi, held 15 minutes with a
bleed off of 141 psi. Sent data to Drilling Engineer, called LOT 575 psi for a EMW of 13.9 ppg. RD test equipment, blew down. Cont circ but hard reset did not
help Sperry tool issue. POOH from 3166' to HWDP at 785'. Racked back HWDP and jars, L/D NM flex DC's (only one lift sub), held PJSM, removed sources, did
not bother with plug in and download on rig floor, L/D smart tools, pulled bit to floor, graded 1-1 and in gauge. Clean floor, clear catwalk, stage replacement BHA
on catwalk. PU DM, EWR-5, ILS, ALD, CTN and TM collars. Plugged in and uploaded MWD data, shallow pulse tested, held PJSM and loaded sources, cont
RIH with HWDP and jars to 743'. RIH on DP from 743' to 1108' and fill pipe, cont. RIH T/3215'. Washing last std. to bottom. P/U-70K S/O-50K ROT-60K GPM-
400 SPP-1050 psi TQ-6K MW-10 ppg ECD-10.4 ppg Max gas- 10 units. Obtained new SPR's. Resumed directional drilling 8.5" production hole F/3215'-T/3465'.
P/U-84K S/O-50K ROT-62K GPM-525 SPP-1800 psi TQ-10K WOB-7K Diff-200 ROP-120 RPM-60 MW-10 ppg ECD-10.6 ppg Max gas- 692 units. Crew change,
held PTSM. Cont. directional drilling 8.5" production hole F/3465' to current depth of 3711'. P/U-88K S/O-50K ROT-64K GPM-525 SPP-1854 psi TQ-10K WOB-
7K Diff-200 ROP-120 RPM-60 MW-10 ppg ECD-10.6 ppg Max gas- 2822 units. Pumped Hi-Vis walnut/condet sweep @ 3711', sweep came back on time w/
50% increase in cuttings. Obtaining new SPR's at report time. Distance to well plan: 48.20' 48.20' High 5.01' Right.
pumped 322p p g g p p ppg p p p pp
bbls (708 sx) 12 ppg Type I II lead cement at 5 bpm-525 to 254 psi, followed by 62 bbls (314 sx) 15.8 ppg Type I II tail cemen
126 bbls throughout the job
g
Did reciprocate casin
pp p
bled off and floats held
gqpp
Witness of BOP test was waived by AOGCC Jim Regg
gg g g
Currently drilling new formation at 3198
pgpppg
singling in hole with 9.625" TXP BTC 47# L-80 surface casing
gp g pp p
called LOT 575 psi for a EMW of 13.9 ppg
pp ppppg p
Did bump the plug 228 bbls into displacement (calculated 227.34 )p
Had 60 bbls. of Spacer returns to surface and 131 bbls lead cement to surface
ppg p (
8/9/2023 Cont drilling 8 1/2" hole from 3711' to 4044'. Rot wob7K, 520 gpm-1790 psi, 60 rpm-7650 ft/lbs on bott torque, 40 to 120 ft/hr ROP. MW 10.1/vis 54, ECD's at
11.0 ppg, BGG 23 units, max gas 536 units. Started adding black product at 3914'. Cont drilling from 4044' to 4207'. Rot wob 5-7K, 524 gpm-1984 psi, 60 rpm-
8500 ft/lbs on bott torque, 25 to 120 ft/hr ROP. MW 10.2 ppg/vis 57,ECD's 10.9 ppg, BGG 86 units, max gas 2530 units at 4145', 1239 units at 4207'. At 4145'
gas climbed to 2530 units at kelly down, cont to circ and work pipe until gas dropped off, nudged MW up to 10.2 ppg. CBU at 522 gpm-1824 psi, 60 rpm-8600
ft/lbs off bott torque, cont circ out gas that spiked at 1239 units at kelly down. Obtained on bottom survey, SPR's and flow check = static. Pulled up hole on
elevators from 4207' to 3308', up wt 98K, dwn wt 55K. At 3308' pulled 20K over multiple times (sand into claystone and bottom of a slide) and could not get
through. MU topdrive started pumping and packed off. Shut down pump, worked pipe free,. started pumps with no issue, started rotating and stalled topdrive.
Cont to work free, washed and reamed down to 3336' at 515 gpm-1745 psi, 60 rpm-6600 to 7000 ft/lbs torque, backreamed up to 3275' with no issue, shut down
rotary and pumps, worked full stand no issues. Cont pull up hole on elevators from 3275' to 3152' and parked string. Calc hole fill = 5.63 bbls, actual hole fill =
6.45. Serviced rig and topdrive, electrician checked service loop connection on topdrive (loose) and tightened same. Re-clocked kelly hose, ran up through
derrick to verify clearance, checked saver sub (ok), cleaned suction screens. TIH on elevators from 3152' to 4146' with no issues, MU topdrive on last stand,
filled pipe, washed and reamed to bottom at 4207'. Pumped 20 bbl hi-vis nutplug sweep around at 524 gpm-1863 psi, 60 rpm-8463 ft/lbs off bott torque. Hole
unloaded at bottoms up, and again with sweep to surface. Cont to circ until shakers cleaned up. ECD's down to 10.9 ppg, Max gas 148 units at bottoms up then
down to 22 units. Cont. directional drilling 8.5" production hole F/4207'-T/4475'. P/U-98K S/O-55K ROT-68K GPM-525 SPP-2090 psi TQ-10.2K WOB-7K Diff-
180 ROP-120 RPM-60 MW-10.25 ppg ECD-10.9 ppg Max gas- 2185 units. Crew change, held PTSM. Cont. directional drilling 8.5" production hole F/4475' to
current depth of 4829'. P/U-97K S/O-57K ROT-72K GPM-525 SPP-2065 psi TQ-10.3K WOB-3/7K Diff-150 ROP-120 RPM-60 MW-10.3 ppg ECD-10.9 ppg Max
gas- 3242 units. Pumped Hi-Vis walnut/condet sweep @ 4705', sweep came back 12 bbls early w/ 10% increase in cuttings. Obtaining new SPR's. Started
weighting up to 10.3 ppg @ 4829'. Distance to well plan: 44.06' 43.21' High 8.61' Right.
8/10/2023 Cont drilling 8 1/2" hole from 4829' to 5151'. Rot wob 7K, 514 gpm-2147 psi, 60 rpm-10,000 ft/lbs on bott torque, 50 to 120 ft/hr ROP. Slidingwob 3-5K, 485 gpm-
1919 psi, 78 psi diff, 20 ft/hr ROP. MW 10.3/vis 45, ECD's at 10.9 ppg, BGG 52, max gas 4078 units at 4952'. Cont drilling from 5151' to 5260', rot wob 5-7K,
515 gpm-2088 psi, 70 rpm-10,600 ft/lbs on bott torque, 60 to 95 ft/hr ROP, MW 10.3/vis 45, ECD's 10.9, BGG 51 units, max gas 451 units. Circulated surface to
surface at 516 gpm-2115 psi, 70 rpm-11,100 ft/lbs off bott torque. Added 1/2 drum NXS lube to suction pit to reduce drag in surface pipe during wiper trip (S
curve), got on bottom survey and SPR's, flow check = slight seepage. Pulled up hole on elevators from 5260' to 4452', up wt 118K, dwn wt 55K, had numerous
20 to 30K overpulls we were able to work through on elevators. At 4452' had to MU topdrive and backream up to 4392', then pulled on elevators to 4208' and
parked string. Serviced rig and topdrive, cleaned pump suction screens, replaced pump #1 pump throttle control in doghouse, checked pulsation dampeners.
CBU to test run pump #1 throttle control, 509 gpm-1924 psi, 70 rpm-9300 ft/lbs off bott torque. Hole unloaded pretty good at bottoms up, max gas 89 units. Once
shakers cleaned up shut down for TIH. RIH on elevators F/4208'-T/5260' w/ no issues washing last std. to bottom. P/U-125K S/O-65K Calculated pipe
displacement-19.52 bbls Act-19.35 bbls Diff-.17 bbls over. CBU, hole unloaded w/ 100% increase in cuttings (shards of coal), Max gas at BU= 573 units. GPM-
519 SPP-2098 psi TQ-11.3K RPM-70 MW-10.35 ppg ECD-11 ppg. Pumped 40 bbl walnut/condet Hi-Vis sweep, sweep came back on time w/ a 50% increase in
cuttings. Cont. drilling 8.5" production hole F/5260'-T/5405'. Turned on centrifuge to work on cutting MW back to 10.1 ppg. P/U-130K S/O-65K ROT-86K GPM-
515 SPP-2150 psi TQ-12.5K WOB-8K Diff-180 ROP-120 RPM-60 MW-10.25 ppg ECD-10.7 ppg Max gas- 2725 units. Crew change, held PTSM. Cont. drilling
8.5" production hole F/5405' to current depth of 5732'. P/U-132K S/O-70K ROT-90K GPM-515 SPP-2204 psi TQ-12K WOB-8K Diff-160 RPM-60 MW-10.1 ppg
ECD-10.7 ppg Max gas- 1441 units. Distance to well plan: 32.69' 32.68' High .82' Left.
8/11/2023 Drilled 8 hole from 5732 to 5850 md/5435' tvd, rot wob 7K, 509 gpm-2259 psi, 60 rpm-11,400 ft/lbs on bott torque, 60 to 90 ft/hr ROP, MW 10.1/vis 46, ECD's
10.7 to 10.8 ppg, BGG 60 units, max gas 380 units. Circulated surface to surface at 521 gpm-2193 psi, 60 rpm-10,750 ft/lbs off bott torque, max gas 258 units,
obtained on bottom survey, SPR's and flow check was static. Pulled up hole on elevators from 5850' to 5252', up wt 140K, fought 7 tight spots on elevators of 20
to 40K overpull. CBU at 5252', 515 gpm-2082 psi, 80 rpm-11,300 ft/lbs off bott torque. Hole unloaded with 50% increase in cuttings, max gas 386 units. Cont pull
up hole from 5252' to 4078', up wt 125K, dwn wt 68K, at 4140' had to backream up to 4078'. At 4078' CBU twice at 505 gpm-1852 psi, 85 rpm-9675 ft/lbs off bott
torque, good amount of cuttings again at bottoms up that just kept coming and max gas of 144 units. Cont pull up hole from 4078' to 3269', up wt 110K, dwn wt
54K. Calculated hole fill = 14.46 bbls, actual hole fill = 15.91 bbls. Held kick while tripping drill at 3893'. With most of BHA outside shoe, CBU at 510 gpm-1754
psi, 30 rpm-5361 ft/lbs torque. 10% increase in cuttings, max gas 536 units. Serviced rig and topdrive, changed swab on mud pump #1, pod #3, cleaned suction
screens, changed trans oil and filters on pump #2. Well on trip tank and at 1.2 bph loss rate. TIH on elevators from 3269' to 4522', dwn wt 51K. Filled pipe and
circ one string volume. Cont TIH from 4522' to 5650' where we set down 3 times 5 to 10K (fresh cut claystone). MU topdrive and filled pipe intending to wash and
ream last 3 stands to bottom. Calc dis = 46.36 bbls, actual = 42.57 bbls. Started washing/reaming down from 5632', 514 gpm-2245 psi, 70 rpm-11,447 ft/lbs
torque, gas started increasing, Parked kelly down at 5683', reduced pump rate to 221 gpm-492 psi, had max gas of 5000 units. Hole unloaded fine silt/clay. Cont
to circ until gas down to 50 units. No alarms activated. Washed and reamed last two stands to bottom, 5850', at 506 gpm-2271 psi, 70 rpm-10,000 to 12,000
ft/lbs torque. CBU at 5850', 523 gpm-2304 psi, 70 rpm-11,540 ft/lbs torque, max gas 325 units. Followed that with a 40 bbl hi-vis nutplug sweep at 525 gpm-2182
psi, 80 rpm-12,000 ft/lbs torque. Sweep came back on time, w/ 80% increase in cuttings. Control drilled 8.5" production hole through low pressure zones T4 &
T6 F/5850'-T/5924'. P/U-135K S/O-66K ROT-85K GPM-369 SPP-1440 psi TQ-12.5K WOB-14K Diff-200 ROP-50 RPM-80 MW-10.1 ppg ECD-10.4 ppg Max gas-
144 units. Crew change, held PTSM. Cont. control drilling 8.5" production hole through low pressure zones T4 & T6 F/5924' to current depth of 6080'. P/U-130K
S/O-67K ROT-91K GPM-350 SPP-1294 psi TQ-11.4K WOB-5/15K Diff-130 ROP-50 RPM-80 MW-10.15 ppg ECD-10.5 ppg. Max gas- 337 units. Distance to
well plan: 26.84' 26.33' High 5.23' Left.
8/12/2023 Cont controlled drilling from 6080' to 6187', rot wob 6 to 12K, 346 gpm-1325 psi, 80 rpm-12,600 ft/lbs on bott torque, 10 to 48 ft/hr ROP, MW 10.1/vis 48, ECD's
10.5, BGG 42 units, max gas 157 units. At 6125' ROP dropped to 5 ft/hr, after trying numerous parameter changes. added 2 sacks nutplug and half drum NXS
lube to suction pit. At 6139' ROP increased to 20+ ft/hr. At 6187 pumped a 20 bbl low-vis nutplug sweep around prior to drilling ahead, 360 gpm-1641 psi, 70
rpm-12,800 ft/lbs on bott torque. Had no increase in cuttings. Cont drilling from 6187' to 6325', rot wob 6 to 15K, 366 gpm-1738 psi, 60 to 80 rpm-12,100 to
13,100 ft/lbs on bott torque, 20 to 50 ft/hr ROP, MW 10.1/vis 46, ECD"s 10.4 to 10.5 ppg, BGG 26 units, max gas 332 units. At 6325' ROP dropped off again to 6
ft/hr ROP. Control drilled 8.5" production hole F/6325'-T/6435'. Cont. changing up drilling parameters to increase ROP. Brought GPM to 400, put 2 sxs of walnut
into suction pit to scrub BHA, and added 1/2 drum of NXS lube to suction pit, with very little to no increase in ROP. Hand drilled F/6327'-T/6335'. Increased WOB
to 18K, started seeing Diff, and ROP took off (50 fph). P/U-143K S/O-76K ROT-96K GPM-400 SPP-1975 psi TQ-12.5K WOB-24K Diff-134 ROP-50 RPM-80 MW-
10.1 ppg ECD-10.5 ppg Max gas- 480 units. Obtained new SPR's @ 6373'. Crew change, held PTSM. Cont. control drilled 8.5" production hole F/6435' to
current depth of 6592'. Increased MW to 10.2 ppg to reduce connection gas. P/U-155K S/O-75K ROT-98K GPM-400 SPP-2018 psi. TQ-12/14K WOB-15/26K
Diff-200 ROP-50 RPM-80 MW-10.2 ppg ECD-10.6 ppg Max gas- 680 units. Distance to well plan: 21.70'. 21.07' High 5.19' Left.
8/13/2023 Cont drilling 8 1/2" hole from 6592' to 6681', rot wob 26K, 402 gpm-2133 psi, 80 rpm-13,300 ft/lbs on bott torque, 10 to 49 ft/hr ROP, MW 10.2/vis 53, ECD's
10.6 to 107 ppg, BGG 29 units, max gas 311 units. Had 9 units connection gas at 6619'. Pumed 20 bbl nutplug sweep at 6635'. Repalced swab and liner one
mud pump #1, pod #3 while circulating and working pipe, also checked upper quill seal on topdrive (leaking gear box oil) and re placed missing rpm magnet.
Cont drilling from 6681' to 6805', rot wob20 to 29K, 402 gpm-2039 psi, 70 rpm-11,900 ft/lbs on bott torque, 20 to 50 ft/hr ROP. Sliding wob 15 to 17K, 403 gpm-
1934 psi, 159 psi diff, 25 ft/hr ROP. MW 10.2/vis 53, ECD's 10.6 to 10.7 ppg, BGG 34, max gas 395 units. 28 units conn gas at 6745'. Cont control drilling 8.5"
production hole F/6805' to wiper trip depth @ 6866'.P/U-160K S/O-76K ROT-100K GPM-400 SPP-2130 psi TQ-14K WOB-30K Diff-240 ROP-50 RPM-80 MW-
10.2 ppg ECD-10.6 ppg Max gas- 618 units. Pumped 25 bbl Low-Vis walnut/condet sweep. Sweep came back on time w/ no increase in cuttings. GPM-400 SPP-
1850 psi TQ-13.5K RPM-70 MW-10.2 ppg ECD-10.5 ppg Max gas- 107 units. Shot on bottom survey, obtained new SPR's, flow check well (static). BROOH
F/6866'-T/5810'. From 6782' to 6374' worked through multiple overpulls and high torque stall outs while BROOH. P/U-156K S/O-74K ROT-100K GPM-400/425
SPP-1905/2130 psi TQ-13/18K RPM-30/80 MW-10.2 ppg ECD-10.7 ppg Max gas- 222 units. Calculated hole fill- 6.03 bbls Act- 21.71 bbls Diff-15.68 bbls over.
CBU @ 5810' while working pipe. GPM-411 SPP-1861 psi TQ-12.2K RPM-80 MW-10.2 ppg ECD-10.26 ppg Max gas- 261 units at BU. Had an 80% increase in
cuttings at BU, mostly clay, w/ sand and coal. Serviced rig while monitoring hole on TT (static). Greased TD, blocks, crown, wash pipe, IR, DWKS, break
linkage, and drive line. Cleaned suction screens on both MP's. RIH F/5810'-T/6741' w/ no issues. Calculated pipe disp.- 13.42 bbls Act- 11.18 bbls Diff-2.24 bbls
loss. Filled pipe, washed last 2 std. to bottom F/6741'-T/6866', w/ no fill on bottom. GPM-411 SPP-1905 psi TQ-14.5K RPM-80 MW-10.2 ppg ECD-10.7 ppg.
CBU at report time. P/U-160K S/O-76K ROT-100K GPM-411 SPP-1965 psi TQ-13.7K RPM-80 MW-10.2 ppg ECD-10.7 ppg Max gas- 348 units. Distance to well
plan: 21.06' 21.04' High .89' Right.
8/14/2023 Pumped 20 bbl Hi Vis nut Plug Sweep around @ 423 gpm 1982 psi 80 rpm 14342 ft/lbs of torque off bottom, sweep back on time 25% increase in cuttings.
Continue Drilling 8.5'' production section f/ 6866' t/ 6993' 425 gpm 2420 psi 80 rpm 12.6k tq on bottom, 230 diff ,18k WOB, Max gas 128 units, MW 10.2 ppg
ECD 10.7 ppg, ROP 4 - 80 Start adding lube bring up to .5%. Continue Drilling 8.5'' Production hole f/ 6993' t/ 7096' 425 gpm 2405 psi 75 RPM 15.5k tq on
bottom 128 diff, 17k WOB, Max Gas Observed 1150 units, MW 10.2 ppg ECD 10.9 ppg Adding lube staging pump rate up slowly 160 PUW 77k SOW 102k
ROT. P/U t/ 7081' and attempt to increase pump rate to 450 gpm rotary stalled no packing off observed, Attempt to work free no luck, continue working pipe
attempt to slump down on string stalling rotary, switch to max torque and attempt slump no luck, over pull no movement, Directional tool face not. changing with
attempted pipe movement and slumping, jars firing, no differential change flow rate and pressure staying constant, continue working pipe over pulling to 240k
80k over original PU weight. notify engineer continue working string, start mobilizing fishing equipment. Cont. working to free hung pipe w/ full circulation.
Cocking jars at 50/60K, slacking off to 40/30K and holding, over pulling 160K over P/U weight, firing jars, picking back up to 280K looking for pipe movement.
Seeing small amounts of coal at shakers during jarring. operations. Performing a derrick inspection after each jarring session. Pulling string into tension at 280K,
chain down break handle, cont. to circulate at 450 GPM, watching for weight to fall off. Brought lube concentration up to 1% by volume w/ NXS lube to reduce.
friction and add lubricity to hole. Cont. working to free hung pipe w/ full circulation. Pumped around 25 bbl steel seal pill (graphite) in attempt to help w/ freeing of
hung pipe while jarring. Pulled to P/U weight of 160K, put 18/20K right handed TQ in string, S/O to 30K, attempting to work TQ down hole. to pop string free.
Distance to well plan: 19.71' 18.92' High 5.53' Right.
8/15/2023 Attempt to work torque down slumping on string, P/U and fire jars multiple times P/U to 260k , no change in string tool face flow rate and stand pipe pressure
normal. Complete Derrick Inspection. Attempt to work torque down slumping on string, P/U and work string up by firing jars multiple times P/U to 290K, Derrick
Inspection after 4 hours of Jarring. No change in string tool face flow rate and stand pipe pressure normal. Continue Jarring operations attempt to free stuck pipe
pull up to 290k fire jars up and down no change attempt to rotate no change, pump weighted Hi Vis Sweep sweep back on time 50% increase in cuttings half
dollar size chunks of coal smaller coal chips. Perform Derrick inspection, Continue Jarring Operations, work string, no change, continue pulling up to 290-300k
jarring up and jarring down. Attempt to rotate string still stalling slump down and attempt to get movement, no change.
8/16/2023 Stop Jarring & L/D Jt. # 206. Torque pump in sub into drill string and circulate through cement standpipe hose @ 265 GPM W/ 1200 psi. Service & Inspect
Blocks, Top Drive, Saver Sub, Floor Motor, Draworks, Crown-O-Matic, Gear Box, Drive Line & Brake Linkage. Cont. Circulate @ 265 GPM W/ 1200 psi. While
performing derrick inspection, C/O Grabber Dies & Confirm Grabber Box is secure. Function Test all Top Drive Functions. All Good. PJSM with Alaska E-Line
crew for string shot run. Remove 3" plug from upper section of Top Drive for wireline tool entry. E-Line rehead line and assemble string shot. Shut down pumps
and B/D standpipe hose. R/U Wireline sheave. Lower e-line through quill on top drive, Assemble tool string with 2 weight bars, CCL & 240 gr. String shot.
Connect E-Line head & M/U Top Drive. RIH T/ Flex Collars & Standby while rig works left hand torque down string of 15K. Lock torque in with grabber box and
weight indicator at 120K. Position string shot @ 6872' md 6835' WLM which is the connection between HWDP Jt. #1 & HWDP Jt. #2. Fire shot with no clear
indication of fire. POOH to check string shot. Shot fired. M/U circulating swedge and Circ @ 250 GPM W/ 1120 psi. while E-Line M/U another string shot with
300 gr. primer cord. M/U 5' drill pipe pup to top of string. M/U second string shot & M/U Top Drive. Remove string from slips and chain down at 80K. RIH with
second shot to Flex Collars. Spend more time working 15K torque down string when pipe came free at 120K up. POOH W/ E-Line. Pump Hi-Vis sweep and
circulate out @ GPM 536, SPP 1502 psi. P/U 114K, S/O 70K. POOH racking back DP, Stand back HWDP and L/D jar stand and last stand of HWDP, that was
shot across, left 214' of fish in the hole. Clear floor and lay out fishing BHA on skate. Replace 3 way 4 position valve on the accumulator unit blind rams. RIH w/
8 1/8'' over shot BHA w/ 5.25'' Grapple, pump out sub, bumper sub, fishing Jar, 6 6 1/2'' Spiral drill collars, Accelerator Jars, and HWDP t/ 3100'.
8/17/2023 Slip and Cut 104' of drilling line. Reset and test Crown-O-Matic. Good Test. Continue RIH with BHA #4, 8.063" Overshot fishing assembly F/ 3100' T/ 3226'
Bridge was detected @ 3226' Attempted to pump and rotate through with no success. POOH F/ 3226' T/ 3135' inside 9-5/8" casing. Service and Inspect Crown,
Blocks, Top Drive, Saver Sub, Iron Roughneck, Floor Motor, Draworks, Gear Box, Drive Line and Brake Linkage. Well remains static. Submitted 48 hour notice
to AOGCC for Bi-Weekly BOPE Test with updates. Decision made T/ POOH for new fishing assembly F/ 3133' T/ 1275' P/U 40K S/O 32K. Trip while tripping drill
with well secured in 40 seconds. Conduct AAR with crew and discussed observations. Continue POOH F/ 1275' T/ BHA. BHA #4 @ 690' Monitor Well, static.
POOH F/ 690' and stand back HWDP and L/D Accelerator. Stand back 6-1/2" Drill Collars, Pull Bumper Sub with lift sub to Oversho t and remove Overshot and
install 4-1/2" IF Box X 4-1/2" CDS40 crossover sub. RIH with 6-1/2" Drill Collars, Accelerator and HWDP T/ 660'. RIH with BHA #5 with screw in sub assembly F/
660' T/ 5000' P/U 108K S/O 66K. Pump Hi-Vis sweep STS GPM 386 SPP 933 psi. No increase on returns. RIH F/ 5000' T/ 6858' wash last stand down F/ 6858'
T/ 6870' tag up on fish set down 10k retag, get parameters PUW 140kk SOW 77k ROT 98k 11.4k free tq. Wash top of fish off, circulate hi Vi Sweep around,
Rotate and engage fish, work down torque, continue working right hand torque into string, Begin Jarring operations stage up to 290k jar licks 200k over, jar down
on fish, free pipe movement established, rack back 2 stands of DP. CBU spot 25 bbl lube pill outside pipe. POOH f/ 6932' t/ 4950' work through multiple tight
spots BROOH, pumping and working string pulling on elevators when allows, 145k PUW 112 ROT 13-18k tq off bottom, CBU @ 6496' hole unloaded alot of
fines.
RIH with BHA #4, 8.063" Overshot fishing assembly
pp p p p g g p g
Spend more time working 15K torque down string when pipe came free at 120K up.
p
E-Line rehead line and assemble string shot
p
RIH with 6-1/2" Drill Collars, Accelerator and HWDP
g
Performing
@p
left 214' of fish in the hole.
ggp p p y
Attempt to work free no luck
gg q
free pipe movement established
8/18/2023 POOH F/ 4950' T/ 4075' work through multiple tight spots BROOH, pumping and working string pulling on elevators when allows, P/U 120K S/O 50K ROT 83K 3-
15K TQ. CBU to even out MW throughout wellbore 10.2ppg in and 10.4ppg out. GPM 257-426 SPP 538-1339 psi. 5 to 6 inches of fine cuttings observed on
shakers and cont. circulating until clean. Continue POOH with BHA #5 Screw in sub fishing assembly F/ 4075' T/ 3160' inside 9-5/8" casing with elevators and
no problems. P/U 115K S/O 60K. Perform Post Jarring Derrick Inspection, Service and Inspect Blocks, Top Drive, Crown, Iron Roughneck and change oil in
transmission on Floor Motor. Cont. POOH F/ 3160' T/ 184' Laying down screw in fishing assembly. L/D HWDP Jt. #1, Stand Back Flex Collars, PJSM & Pull
Sources, Download Data & L/D BHA #3 fish. Bit graded a 1-1 with two chipped teeth and in gauge. pull wear ring, clear floor, R/U stack washer and flush stack.
R/U test equipment set test plug and flood stack and lines, fill choke manifold. Test BOP's w/ 4.5'' test jt t/ 250/3500 psi f/ 5 min each, test CMV 1-13, HCR and
Man Choke and kill valves, TIW and Dart, Auto & Man IBOP, Upper Lower and Blind Rams, Annular, Perform Drawdown test on Acc. 24 sec f/ 200 psi 84 sec t/
FP bottle avg 2625 psi, State Inspector Jim Regg Waived Witness. R/D Test equipment, set wear ring. Service rig and top drive, grease crown and blocks,
Service inter cooler on Rig floor transmission, Grease Iron Roughneck, Load racks w/ Drilling BHA. M/U Directional BHA #6 as per DD/MWD, Upload MWD.
8/19/2023 Continue uploading MWD on BHA #6. Shallow pulse test @ 400 GPM, Good. RIH with 1 stand Flex Collars and 2 stands of HWDP, P/U Jar and single Jt.
HWDP. RIH with 5 stands HWDP T/ 640'. RIH with directional BHA #6 with no nukes or stabilizers. With 4-1/2" CDS40 Drill Pipe F/ Derrick F/ 640' T/ 3177'. P/U
73K S/O 56K. CBU inside 9-5/8" casing @ 3177' GPM 357-250 SPP 1015-520psi. Max gas at 5000 units entrained in mud. RIH on elevators F/ 3175' T/ 4355'
P/U 85K S/O 62K. Wash and Ream through tight spots at 3892' & 3900' GPM 400 SPP 1500psi. RPM 60 Calculated displacement 71.06 BBLs Actual
displacement 66.86 BBLs. Continue RIH F/ 4355' T/ 5279' on elevators with no problems P/U 110K S/O 62K. CBU while reciprocating and rotating. GPM 251
SPP 753psi RPM 60 TQ 10K Max gas 4508 units entrained in mud. Continue RIH with Directional BHA #6 F/ 5279' T/ 7096' Washing & Reaming last 4 stands
GPM 350 SPP 1500psi RPM 60. Max Gas 3393 units entrained in mud. SPRs @ 7096' MD 6664' TVD MW10.3ppg MP#1 15 SPM 189psi 30 SPM 185psi MP#2
15 SPM 187psi 30 SPM 183psi. Drill 8.5'' Hole section f/ 7096' t/ 7295' 437 gpm 2090 psi 80 rpm 15k tq on bottom, MW 10.2 ppg ECD 10.66 ppg Max Gas 403
units, 140k PUW 84k SOW 102k ROT. Drill 8.5'' Hole section f/ 7295' t/ 7400' 440 gpm 2200 psi 80 rpm 10.2k tq on bottom, MW 10.15 ppg ECD 10.64 ppg Max
Gas 30 units, 140k PUW 84k SOW 102k ROT, Distance to plan 18.79' 14.21' High 12.30' Right.
8/20/2023 Drill 8.5'' Hole section F/ 7400' T/ 7501' GPM 440 SPP 2200 psi RPM 80 TQ on bottom 12.2K MW in/out10.25 ppg ECD 11 ppg Max Gas 513 units, P/U 140K
S/O 85K ROT 106K. While drilling ahead Torque increased F/ 13K T/ 20K, Drill string was hoisted with intent of back reaming. Torque increased T/ 20K while
back reaming. Attempted to rotate after slacking off to a neutral weight. Rotation & Hoisting stopped. Begin Jarring while pumping through drill string. Perform
Jarring Derrick Inspection. Inspect Draworks & Top Drive. Continue hitting drilling jars in an attempt to free BHA while pumping GPM 400 SPP 1900 psi. While
waiting for E-Line to arrive. Post Jar Derrick Inspection. Grease and Inspect Blocks, Top Drive, Iron Roughneck and Check fluids in all motors. Spot E-Line unit,
PJSM, Re-Wire head & assemble String Shot. Stop pumping downhole and B/D Top Drive. Remove plug on top of Top Drive for E-Line passage. Place well on
trip tank & monitor well. R/U Sheeve in Derrick and assemble tool string with 2 weight bars, CCL & SS. RIH W/ 240 Grain String Shot, CCL & Two weight bars,
RIH t/ depth work left hand torque to bottom 17k lock in and set string @ 86k hook load, corelate with eline and fire string shot, Pull up hole with eline park tools
and work left hand torque down string free 120k PUW, POOH w/ Eline and pull head. through top drive, R/D tool string and M/U cap on mud line. Work String
and break circulation 462 gpm 1300 psi 60 RPM 12k tq R/D ELine Sheave and release. POOH f/ 7315' t/ BHA Stand Back in Derrick Left 173' of fish in the hole.
M/U Fishing BHA , Screw in Sub, Jars, Bumpers sub, Accelerator, and DC, RIH t/ 3138' inside the shoe. Slip and cut drilling line and service rig.
8/21/2023 Continue RIH with BHA #7 Screw in Fishing assembly F/ 3138' T/ 7273' & Tag Fill. P/U 132K S/O 72K. Calculated Displacement 51.62 BBLs Actual
Displacement 49.88 BBLs. Wash down without rotation F/ 7250' T/ 7324' tagging fish. Pump Hi-Vis sweep STS @ GPM 420 SPP 1200 psi. RPM 45. Sweep
came back on time with no increase in cuttings. Locate top of fish on first attempt & torque up connection working torque down. Begin Jarring @ 09:50. Jar on
fish with pulls up to 300K & work fish down 2' by slumping down. Continue to Jar up F/ 260K T/ 300K. Sheared circ sub & pumping at 345 GPM W/ 1500 psi.
Derrick Inspection after 4 hours of jarring. Service & Inspect Top Drive, Blocks, Brakes, Drive Line & Brake Linkage. Continue Jarring with Derrick Inspections
every four hours. Working by Changing pump speeds & Jarring up and Slumping down. Attempt to back off fish, work left hand torque down, continue working
string, 17k left hand torque working down Saver sub broke, retighten and continue working left hand torque down, backed off jt of DP somewhere up hole 50k
PUW, set down and screwed back into string continue working torque down. Continue jarring and slumping on string no movement, vary pump rates and keep
working to free pipe, Large chunks of coal coming across shakers at various times, Perform derrick inspection in between jarring operations.
8/22/2023 Cont to jar and slump while circ at 426 gpm-1461 psi, working from 20K up to 320K. MW 10.2+/vis 53, BGG 8 units. Parked string at 85K, inspected and
pressure washed in derrick while circ at 425 gpm-1445 psi. Resumed jarring alternating between 290K and 310K, circulating at 426 gpm. Jars fired 20 times
then quit firing. Alternated slack off and PU weights, pump rates etc with no luck. Cont to circ and clean in derrick for an hour, stroked pipe one time and parked
at 290K, jars fired, attempted to. re-cock and fire jars numerous times with no luck. Parked string at 95K, cont to circ at 225 gpm-435 psi, cont waiting on e-line
to arrive on location. Set slips and break off top drive blow down and break plug on top of top drive, R/U AK ELine and RIH w/ 2'' Spilt shot corelate and pull
tension on string park string at 260k hook load, get on depth and fire shot across crossover to flex collars, very slight movement on surface, 2-4k drop in weight.
P/U on eline to clear shot to work string free, eline hung up, attempt to work tool string free unable, work DP attempt to assist eline tools, set down and cock jars,
P/U and park tool string @ 260k Jars fired and DP was free, eline string still stuck, contiune working eline, unable to free eline,. eline pulled out of rope socket @
3350 lbs, POOH, R/D eline, tool string left in pipe approximately 23' of fish. POOH w/ DP f/ 7358' t/ 690' no hole issues, Flow check well static.
8/23/2023 Cont POOH to fishing BHA at 460'. Racked back HWDP, L/D accelerator sub, 6 x spiral DC's, fishing jar and bumper sub. Found 10.5' e-line tool string in the XO
on bottom of pump out sub. L/D XO and removed e-line tools, Recovered and L/D one joint HWDP with split pin end. Functioned blind rams, cleaned and
cleared rig floor and catwalk, staged cleanout BHA items for PU. Monitored well on trip tank, hole took .10 bph. MU 8.5" tri-cone, bit sub with float, 8.310" OD
ILS, XO, 4 jnts HWDP, jars, XO and 11 jnts HWDP to 510'. Cont TIH on 4 1/2" DP from 510' to 1500', filled pipe, TIH to 3045', filled pipe and CBU at 263 gpm-
324 psi with a max of 7 units gas, TIH to 4500' and filled pipe, TIH to 6000' and CBU at 428 gpm with a max of 79 units gas, TIH to 7268' filled pipe,
washed/reamed down to 7308'. Pumped a 23 bbl hi-vis nutplug sweep around at 441 gpm-1436 psi, 60 rpm-8317 ft/lbs off bott torque. Sweep was 200 strokes
late (12 bbls) and maybe 10% increase in fine cuttings. had a max of 183 units gas. Flow check was static. POOH on elevators f/ 7308' t/ 510' L/D HWDP and
clean out BHA. Bit graded 2-1 in gauge. Clean and clear floor. Service rig and top drive grease blocks and crown, inspect draw works. R/U t/ run 4.5'' JFELION
liner, PJSM, M/U float equipment backer locking jts, check floats, floats good continue RIH M/U connections t/ 6690 ft/lbs installing centralizers every other jt.
pgjp
Recovered and L/D one joint HWDP with split pin end
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Left 173' of fish in the hole
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washed/reamed down to 7308'.
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RIH w/ 2'' Spilt shot corelate and
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string free 120k PUW, POOH w/ Eline and pull head
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D HWDP Jt. #1, Stand Back Flex Collars, PJSM & Pull
Sources, Download Data & L/D BHA #3 fish
fire string shot
8/24/2023 Cont PU single in hole with 4.5" 12.6# L-80 JFE Lion liner pipe from 1915' to 3167' filling on the fly, topping off every 10 jnts, down weight 35K. MU circ swedge,
CBU x2 staging up to 223 gpm-91 psi, max gas 20 units. Cont PU single in hole from 3167' to 4299', ran total 137 joints 4.5" liner. C/O handling equipment, PU
Baker liner hanger assembly, as we went to install 7" x 4.5" XO on bottom, found the catch collar to be 4.49" OD and would not pass through XO or fit in liner
pipe. RU head pin on stump. Circulated on liner with headpin and TIW at 111 gpm-111 psi, removed catch collar from liner hanger run tool, attempted to chase
down a collar in field with no luck. Flew collar to Nikiski and had machined down from 4.49" to 3.75" OD, flew collar back to Beluga. Max gas 46 units, strapped 4
1/2" JFE Lion pipe on H pad for tieback run, loaded Sperry tools for this evenings barge loadout to Homer. Catch collar on location at 18:15, MU catch collar, MU
7" x 4.5" XO on hanger, MU LWP swivel and liner wiper plug. MU 4' JFE pup to hanger, installed hanger on stump, torqued connections as per Baker Rep,
mixed and poured Xanplex, installed 4 1/2" IF pin x CDS-40 box XO on run tool, RIH one stand DP and MU topdrive. Circ on liner at 286 gpm-350 psi, broke off
topdrive. Cont RIH on 4 1/2" DP from 4407' to 7349'. M/U cement head w/ 10' and 15' DP pup jts, establish circulation, stage pumps t/ 5 bpm, spot in cementers
and R/U Lines. PJSM, Pumped 5 bbls to fill lines, Shut in and PT Lines t/ 432 / 4494 PSI High and Low test, Lined up down hole and pumped 30 bbls 10.5 ppg
spacer 4 bpm 290 psi followed by 361 bbls (845 sx) 12 ppg Type l ll Lead cement 5 bpm 245 psi, pumped 38 bbls (181 sx) 15.3 ppg Type l ll Tail Cement, 2 pps.
LCM in lead Cement, Washed up over top of head, Dropped Dart, Displaced 104 bbls 10.2 ppg 6% KCL Mud, 106 bbls Calculated, slowed pumps t/ 2 bpm w/ 16
bbls to go 1220 psi, pressured up t/ 1700 psi held f/ 5 min, bled of checked floats 1 bbls bled back, Pressure up t/ 2400 psi Slack off f/ 90k. to 30k setting
hanger, pressure up t/ 3900 psi and set packer, Pressure up t/ 4300 psi and neutralize Pusher Tool, Bleed off pressure and P/U verify released 52k PUW, CIP
04:21 hrs 8/25/23 Total losses through out Job 103 bbls, 30 bbls spacer back 68 bbls cement contaminated mud, L/D Cement Head.
8/25/2023 LD single jnt DP and 10 pup, MU topdrive, circulated STS twice at 348 gpm-386 psi, flushed and blew down cement lines and manifold. RD released GeoLog
mud loggers. POOH on alternate breaks from 2970' to surface and L/D Baker run tool. Sent AOGCC notification for witness of upcoming MIT-T and MIT-IA. PU
Baker cement head and removed pup jnts and XO's, PU kelly jnt and diffuser, drained stack then flushed stack and flow line with black water, LD kelly jnt and
diffuser. PU Baker "TBR" dress and polish mill assembly. Found the top dressing mill was 8.74" OD (surface casing 8.681" ID), removed top dress mill from
assembly, MU XO, RIH one stand DP, installed dart valve, cont TIH from 81' to 2958', filled pipe at 1500' and 2958'. Circ at 110 gpm- eased down into SBR and
tagged with polish mill at 3012' (TOL at 3000'), dressed SBR as per Baker Rep with 30 rpm-2950 ft/lbs torque, up wt 48K, dwn wt 45K. Parked just above SBR,
pumped 25 bbl hi-vis weighted spacer followed with inhibited fresh water with both pumps and displaced well to IFW at 310 gpm-152 psi. Cleaned up under
shakers and flow trough. Built more IFW for POOH. Witness of MIT waived by Jim Regg at 16:08. POOH LD 4 1/2" DP, CCI vacuuming wiper balls on pipe rack.
Up wt 56, f/ 2954' t/ Surface L/D Polish Mill Assembly, R/D Geo Span In cellar. RIH w/ 40 stands of DP t/ 2472' POOH L/D DP same. R/U and test Liner Lap t/
3500 psi f/ 30 min pumped 3.8 bbls in 3.6 bbls bled back. RIH w/ 39 stands f/ Derrick POOH L/D Same. Pull Wear ring, Flush Pocket, R/U Parker TRS, Load
trailers and racks w/ Tie Back.
8/26/2023 Clean and clear rig floor, C/O handling equipment to run liner, stage seal assembly, transport trailer of 16 jnts from D pad to C pad and load pipe racks, start
transport of liner trailers from Beluga H pad to rig, held PJSM with rig crew, Baker Rep and Casing crew. MU Baker 7.375" Bullet Seal Assembly, PU and single
in hole with 4 1/2" 12.6# L-80 JFE-Lion pipe, torqued to 6690 ft/lbs, to 1491' (47 jnts). MU chemical injection mandrel, staged spooling unit, hung overhead
sheave, tie in control line and test to 2000 psi for 10 minutes, good test. Cont PU single in hole from 1491' to 2979'. PU two extra joints and tagged no-go, up wt
38K, dwn wt 34K. L/D two joints, MU 9.78' of pup joints to put no-go 1.80' off seat when landed. MU landing joint and hanger, terminated control line in bottom of
hanger. Pollard RU on top port. and tested control line to 2500 psi, good test. Drained BOP stack and with annulas open, S/O and landed hanger, dwn wt 34K.
Wellhead Rep RU and tested hanger seals at 5000 psi while RD overhead sheave and casing tongs. RD test equipment, rotated landing joint6 rnds to left to
activate locking ring, then 3 rnds to right. Pull tested against hanger to 55K (40K over block weight), S/O and rotated landing joint 17 rnds to the right to release
from hanger. L/D landing joint. Flooded BOP stack with water, RU test equipment and purged air, closed blinds, installed psi gauge on IA, lined up to pump down
kill line with test pump. Pumped 1.48 bbls to achieve 3600 psi on tubing/liner. Held good for 10 minutes then started bleeding down. No real increase in IA
pressure of 50 psi. Bled off, greased outside kill valve and cycled same. Pumped 57.5 gallons to achieve 3580 psi on tubing, 145 on IA. Tubing bleeding down
after a couple minutes, IA increased to 168 psi. Bled off everything, PU landing joint. Engaged landing joint on hanger and topped off with water, RU test pump
on IA and pressured up to 3600 psi. Water flow out the top of landing joint, pressure bled down 150 psi on IA over 30 minutes. Discussed with Drilling Engineer,
decision made to pull string, check seals. Removed landing joint, installed retrieving tool, RIH and engaged hanger with 14.5 rnds to the left, then 6 rnds to the
right, pulled to 44K and pulled hanger to rig floor, up wt dropped off from 44K to 38K (previous up wt) as seals exited SBR. RU tubing tongs on rig floor, staged
spooling unit, hung sheave. Held PJSM, removed control line from hanger, broke off landing joint/hanger and LD same. POOH f/ 2988' t/ Surface, Clean and
inspect seals no signs of damage, Discuss options with engineer, decision made to PU 4 1/2" DP and make a second cleanout run with polish mill assembly
(using top dress mill from 151). Make arrangements to get top dressing mill section flown over from rig 151, CCI transporting 3000' 4 1/2" DP from Beluga J pad
back to rig, gathered up 8.5" PDC bits, breaker and gauge ring for return trip to rig 151.
8/27/2023 Transported two 8 1/2" PDC bits, breaker and gauge ring to airstrip for transfer to 151, returned to rig with 8.25" top dressing mill from 151. Transported first
bunk of 4 1/2" DP from Beluga J pad to rig. Racked and tallied 40 jnts DP. PU polish mill, installed 8.25" top dressing mill in assembly and torqued to spec's,
(10.38' below the brass on upper mill to bottom of polish mill, SBR = 11.98'), installed wear ring. PU 1st single and MU dart and XO on polish mill, singled in hole
with 4 1/2" CDS-40 DP from 22.53' to 2983' drifting each joint, (filled at 1559') and MU topdrive. Filled pipe, increased to 223 gpm-68 psi, 40 rpm-4200 ft/lbs
torque, eased down into liner top at 3000', S/O and tagged liner top with dress mill, lower mill at 3010.38'. Reciprocated mills and re-tagged 5 times as per Baker
Rep, de-burred lienr top at 5100 ft/lbs, PU out of SBR. and increased pump rate to 297 gpm-137 psi and CBU. Staged vac truck at pipe rack to vacuum wiper
balls in joints. POOH L/D DP from 2982' to surface, L/D dart, XO and polish mill assembly. Drained BOP stack, removed wear ring, C/O handling equipment and
hung tubing tongs, PU seal assembly, cleaned and inspected box threads, inspected seals (good). PU 1st jnt JFE-Lion off catwalk, cleaned/inspected threads,
MU on seal assembly. Cont TIH from derrick with 4 1/2" tieback string, cleaning, inspecting and lightly doping each connection, torqued to 6690 ft/lbs. 1495' P/U
Chemical injection mandrel and hook up control line and test t/ 2000 psi. Continue RIH inspecting every connection, re doping and torqueing every connection,
Change out one joint with bad nose seal, Continue running in to 2988'. M/U hanger and space out pups, terminate control line, Land on hanger and test seals t/
5000 psi f/ 15 min. R/U test equipment and test IA t/ 3500 psi, Same slow leak, fluid continuously coming out tubing, lost 175 psi in 30 min. L/D Hanger and pup
jts.
8/28/2023 PU jnts #100 and 102, eased in hole seeing seals enter SBR and set down 20K twice on no-go. POOH LD two joints, calculated space out, MU 8.1 of cleaned
and inspected/lightly doped space out pups to give us 1.09 off seat with no-go, MU landing jnt/hanger, terminated and tested control line at. hanger to 2500 psi,
drained stack, S/O and landed hanger, dwn wt 34K. Wellhead Rep tested hanger seals at 5K, good test, activated lock ring on hanger as per Wellhead Rep and
pull tested 40K over block weight. Rotated landing joint fully into hanger and RU test pump on IA. Topped off landing joint with water, pressured up to 3500 psi
on IA. Water continuously running over top of landing joint, lost ~140 psi over 30 min on IA. Discussed with Drilling Engineer, decision made to call out e-line for
WRP and tubing punch, slickline for D&D hole finder and pack off plug. Set up e-line and slickline to travel to Beluga, loaded and shipped out cement silo and
upright water tank from D pad, pulled water pump and pipe from water well on D pad, spooled up electric cords for Sperry and GeoLog units, loaded and shipped
out upright water tank and GeoLog shack,. loaded and shipped out Sperry shack, locker boxes and GeoSpan skid. Pollard slickline on location at 18:00, R/U
Lubricator and crossovers, Hang sheave, M/U tool String, M/U test port on lubricator. RIH f/ Surface t/ 2997' WLM Set Plug, Pressure up to 2500 psi f/ 15 min
still bleeding off, Release f/ Plug Pull up the hole and set Plug @ 1530' WLM Pressure up to 2500 psi on tubing, still bleeding off Pull up t/ 1470' set plug and
test tubing t/ 2500 Same bleed rate, POOH t/ 200' set plug and. attempt to release plug, Work string and spang jars attempt to free plug, not moving start jarring
down to shear pin, pin sheared and head free POOH L/D Head and slip line on Slickline unit re head. M/U retrieval tool RIH engage fish, begin jarring and
working tools to free plug no luck.
pp p
bbls spacer back 68 bbls cement contaminated mud,
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floats 1 bbls bled back
Cont PU single in hole with 4.5" 12.6# L-80 JFE Lion liner pipe from
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wed by 361 bbls (845 sx) 12 ppg Type l ll Lead cement 5 bpm 245 psi, pumped 38 bbls (181 sx) 15.3 ppg Type l ll Tail Cement
pp p
Total losses through out Job 103 bbls
tie in control line and
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pressured up to 3500 psipggjygpp
on IA. Water continuously running over top of landing joint, lost ~140 psi over 30 min on IA.
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R/U test equipment and test IA t/ 3500 psi, Same slow leak, fluid continuously coming out tubing
gp
with 4 1/2" 12.6# L-80 JFE-Lion pip
8/29/2023 Cont with slickline jarring on D&D holefinder plug at 200. Pollard Rep sheared off of plug intentially, POOH, slipped and cut 50 of wire. Re-head, MU on jars and
weight bar, RIH and engaged plug. We applied 500 psi on IA in hopes it would leak some pressure under the plug in tubing and assist in breaking loose.
Resumed jarring. Pressure on IA slowly dropped to 475 psi and held there while jarring. Pollard Rep sheared off of plug for slip and cut, bled off 475 psi from IA,
POOH and slipped/cut 50' of wire. Pollard Reps C/O, MU tool string, RIH, tagged plug 2' higher in tubing. Resumed jarring a dozen times, plug came loose,
dragged plug up hole having to work it at 106' and 80'. Pulled tool string into lubricator, broke off same, recovered the plug, LD tools, RD released Pollard
slickline. Called out e-line crew. Wait on e-line crew (having issue getting truck started), wait on READ Rep to fly in from Anchorage with acoustic tools.
Removed 4 1/2" Bowen XO from stump, spotted e-line unit at 14:30, hung sheave, READ Rep on location with tools at 15:00. Strung wire, MU tool string, RIH
logging down with no pressure on IA to 3009'. With test pump pressured up to 3500 psi on IA, Started logging back up hole. IA lost 20 psi over 30 minutes and
appears to be holding. Cont. logging up hole to surface w/ no signs of fluid. flow to tubing side w/ acoustic sonic tools on E-line. Hung off E-line tools. Made call
to town, decision was made to rest IA & tubing T/3500 psi. Performed MIT-IA test, pressured up IA T/3600 psi, had 525 psi on tubing. Lost 30 psi over 30 min
test (good test), Pumped in 2.6 bbls Bled back 2.5 bbls. Performed MIT-T test. pressured up tubing T/3700 psi, pressure dropped T/3350 on tubing in 30 min,
pressure. on IA increased from 320 psi to 500 psi in 30 min w/ a definitive indication of a leak from tubing to IA. Pumped in 1.55 bbls Bled back 1.3 bbls (failed).
Discussed further options w/ town. Decision was made to retest IA and see if it would leak through to tubing side, run E-line acoustic sonic tool and identify leak.
Apply 3500 psi on IA for 30 min, tested like a jug. Pumped in 2.2 bbls Bled back 2.2 bbls (good test). Lined up and rest tested down tubing. Pressured up on
tubing T/3640 psi, had 300 psi on IA. In 15 min lost 190 psi on tubing to IA. Made call to town, decision was made to POOH L/D all 4.5" JFE lion tie back tubing
and replace w/ new. R/D testing equip. and AK E-line tools/unit. Gave WHR, Pollard control line hands, and TRS casing hands 1 hr. notice. B/O and pulled LJ to
rig floor. Installed hanger retriable tools on bottom of LJ. Latched onto hanger, unseated hanger and pulled tubing hanger too rig floor as per WHR. De-
completed control line. L/D tubing hanger & pup, B/O space out pups. POOH L/D 4.5" JFE lion. singles and removing control bands F/3009' to current depth of
1919'.
8/30/2023 Cont POOH from 1919' L/D 4 1/2" tubing to 1440', removed and secured control line, L/D injection mandrel, cont POOH L/D tubing to surface. Seals on seal
assembly scarred on one side, bits of brass from polish mill run embedded in some of the seals. Recovered all 108 SS bands. Made arrangements to get seal
assembly flown over from rig 151, serviced rig and topdrive, shipped off used tubing, brought in fresh JFE-Lion tubing and loaded pipe rack. Cleaned all old
dope from connections and thread protectors and inspected all threads (no issues found),. Called out Baker Rep and tong operator, had new seal assembly on
location at 13:30, swapped out 7 XOs and JFE pup, torqued assembly to specs, RU tubing tongs, held PJSM with new crew on tour. PU single in hole with 4 1/2"
JFE-Lion 12.6# L-80 tubing, lightly doping each connection with BestOLife 4010, torqued to optimum of 6690 ft/lbs. At 1503', PU chemical injection mandrel,
BakerLok'd XO pups, installed control line and tested same to 2000 psi, good test. Cont PU single in hole with 4 1/2" tubing F/1503'-T/2965'. P/U space out jts.
Tagged TOL at 3015'. Figured out after using all the JFE lion pups on location we were going to be 6.49' off the NoGo. Found 2 XO pups at Pollard. JFE lion B x
IBT P and IBT B x JFE lion P, M/U together = ~3'. Called town and discussed options w/ drilling engineer. Had XO's run out to OSK heliport and flown over by
Helicopter. Worked on housekeeping and prepping for rig move while waiting on XO pups. Verified measurement on space out pups 1-8 (21'). M/U space out
pups to hanger pup. M/U pups, hanger, and LJ to tie back string. Terminated control line and M/U to hanger. Banded remainder of control line to tubing (total of
100 bands run on string). Tested control. T/2500 psi (ok). Landed tie back hanger on seat, seen tie back seals enter SBR. NoGo locator 3.32' off seat. Locked in
hanger to well head, verified lock in with 40K P/U. Tested hanger seals T/5000 psi test for 15 min (ok). R/U testing equip. Flooded lines w/ water and purged out
air. Currently performing MIT-IA test T/3500 psi on chart for 30 min.
8/31/2023 Performed MIT on 9 5/8" x 4 1/2" IA at 3590 psi for 30 min on chart, 535 psi on tubing, good test. Pumped 2.55 bbls and bled back 2.55 bbls. RU to perform MIT
on 4 1/2" tubing/liner, went to 2100 psi and pressure quickly equalized into IA, test failed. Notified Drilling Engineer. Decision made to test tubing and IA
simultaneously. RU and performed combo test on both tubing/IA simultaneously at 3600 psi for 30 min on chart, good test. Pumped 3.66 bbls and bled back
3.66 bbls. Decision made to run production packer in 9 5/8", new CIM and new tubing hanger. Called out wellhead Rep, pollard control line rep and tong
operator while RD test equipment, Rotated landing joint as per wellhead rep to release lock ring on hanger, opened annulus, unseated hanger and pulled to
floor. Removed control line, L/D landing joint and hanger, broke down spaceout pups. Cont POOH slow, up wt 38K, racking back in derrick, spooling control line
from 2982' to 1516', removed control line and secured in derrick, broke XO pups off CIM and L/D same, cont POOH racking back in derrick from 1499' to seal
assembly, Top and center seals damaged, bottom set looked good. Broke JFE pup off seal assembly and L/D same, closed blinds, cleaned up rig floor,
recovered all 100 SS bands. Tool Push took partial crew to K pad in Beluga, LD felt/liner and available rig mats for BRU 241-23. Cont transporting various
equipment from Lewis River to Beluga. WHR M/U new hanger and pup to LJ. Sent partial crew to K pad in Beluga to M/U spacer spool, diverter T, and annular
to the conductor diverter adapter flange on BRU 241-23. Worked on housekeeping and misc. projects. B/D xo and pup off top of Baker seal assy. Loaded out
Baker tools on float. Cont. w/ prepping of rig for move. Service rig- Inspected & greased crown, blocks, TD, IR, DWKS, wash pipe, brake linkage, and drive line.
Cont. with housekeeping, prepping equip./rig for move, and working on misc. projects while waiting on weather to fly over a CIM and Tri-point packer to Beluga.
9/1/2023 Wait on word for flying production packer and CIM to Beluga, still high winds, no chopper flights/sling loads, changed oil in right angle drive of draw works,
changed oil/filters on gen set #1, RD vacuum degasser in pit 3, got approval and witness waived by. AOGCC Rep Jim Regg to perform bi-weekly BOPE test
early, at 10:54. Replaced off drill side winch cable, shipped out screen and parts connexs, staged test joint and set test plug. Met with and did walk through tour
of rig with SVP Luke Saugier and company. Flooded surface lines and stack, purged air and RU to test BOPE. Sent in BOP test notification and waived once
again by AOGCC Rep Jim Regg at 16:09 via email. Tested all BOPE at 250/3500 for 5 min each (250/2500 on annular). Performed koomey draw down test,
functioned flow show and PVT audio/visual alarms. Cannot get Quadco Rep out to test gas alarms until 9-2 at 14:30. Had 1 F/P on test #3, Kill HCR, serviced,
functioned and retested. Pass. RD test equipment, blew down surface lines, received word chopper is going to fly packer and CIM to Beluga. Tri-Point packer
Rep flying Otter to Beluga. Tri-Point packer and CIM on location at 21:00, Tri-Point Rep on location at 21:00, staged equipment for P/U, worked run tally with
packer Rep,. Held PJSM on running 4.5" JFE lion completion string. PU single jnt 4 1/2" JFE-Lion and MU XO and WLEG, PU 9 5/8" x 4 1/2" Tri-point DLH
hydraulic set retrievable packer. RIH F/52.90-T/1503' at 60 fpm. P/U & M/U CIM, M/U control line and tested connection (ok). Cont. RIH w/ 4.5" JFE lion
completion string F/1503'-T/2962' holding 2000 psi on control and banding as needed to tubular. P/U LJ, hanger, and pup. M/U XO and 18.21' of space out pups
to completion string. Terminated control line and M/U to hanger. Test control line. Connection to hanger T/2500 psi (ok). Installed 100 bands total to 4.5"
completion string. RIH and landed hanger on seat w/ 6.52' of WLEG, X-nipple, 4.5" tubing inside SBR. Liner top @ 3005.4'. Testing hanger seals T/5000 psi for
15 min at report time.
9/2/2023 With hanger seals tested, rotated landing jnt and engaged lock ring, pull tested at 40K, topped off landing jnt with water, dropped ball/rod, MU test sub in top of
landing jnt, installed gauge on annulus valve, pumped 38.75 gallons to achieve 3680 psi. Held 30 min on chart for MIT-T, good test. Bled back 38.75 gallons. RU
on IA and pumped 85 gallons to achieve 3100 psi. Held 30 min on chart for MIT-IA, good test. Bled back 85 gallons. RD test equipment, RD tubing tongs,
spooling unit and sheave in derrick. L/D landing joint, installed 2 way check in tubing hanger. Flushed all surface lines and circ equipment with BaraKlean, blew
everything down. C/O gear oil on topdrive and checked quill for end play (ok). Released rig at 12:00 on 9-2-23.
pp g
Decision was made to retest IA and see if it would leak through to tubing side
pgqp
single jnt 4 1/2" JFE-Lion and MU XO and WLEG, PU 9 5/8"x 4 1/2" Tri-point
gg g
Performed MIT-IA test, pressured up IA T/3600 psi, had 525 psi on tubing. Lost 30 psi over 30
pg
unseated hanger and pulled top
floor.
assembly, Top and center seals damaged, bottom set looked good
g
Latched onto hanger, unseated hanger and pulled tubing hanger too rig floor as per WHR
Performed MIT on 9 5/8" x 4 1/2" IA at 3590 psi for 30 min on chart, 535 psi on tubing, good test.
gg
RU and performed combo test on both tubing/IA simultaneously at 3600 psi for 30 min on chart, good test.
RU to perform MIT
on 4 1/2" tubing/liner, went to 2100 psi and pressure quickly equalized into IA, test failed
ppgg
pp qyq
p ()
run E-line acoustic sonic tool and identify leak
pp g j pp p
Held 30 min on chart for MIT-T, good test. Bled back 38.75 gallons. RU gj g g p p g p g
on IA and pumped 85 gallons to achieve 3100 psi. Held 30 min on chart for MIT-IA, good test. Bled back 85 gallons. RD test equipment
Activity Date Ops Summary
9/10/2023 Check in at Kenai Airport for Beluga. Travel to Beluga River. Check in camp. Meet with Lead Op. PJSM.,Barge of equipment and tide will arrive at 16:00. Travel to
Lewis River to inspect location and rig up. Locate triplex, 2 Rain for Rent tanks, liners & man lift from TMC.,Barge arrives. Offload CT Unit, N2 Unit, Transport,
Cruz crane & vac truck.,Mobe equipment to Lewis River. Spot & secure equipment. Return to base. SDFN.
9/11/2023 PJSM & permit.,Rain for Rent tanks & man lift to location.,MIRU Fox CTU and Cruz crane.,PT 250/3000 front, backside of choke skid and pipe slips. BOPE test
good.,Install CT roller connector, new stripper rubber, hook up hoses and cables. R/U pump unit. Fill coil w/ 24 BBLs FW,Return to camp. SDFN.
Plan forward: Stab injector. Shell test. Displace kill fluid w/ FW. Run HES CBL log.
9/12/2023 Fox Energy & Cruz PJSM & permit. Travel to Lewis River.,Fire equipment. P/U injector head & 3 sections lubricator. M/U 2-1/8" jet nozzle. Stab on to well.,Shell
test 250 / 3000 PSI. Test good.,Open well and RIH.,Sat down at 6794'. (PBTD 7275' for CBL / Btm perf target 6820'). Kicked on pump at 1-1/2 BPM & worked
pipe. Could not pass. Notify town. Town advised mill & motor to clear possible cement stringers. Dispatch Yellow Jacket for tools & hand. POOH.,POOH.,OOH.
Break off and cut off crimp connector. Stand by for YJ to arrive.,YJ arrive at Beluga. Load out tools & travel to location.,Arrive location. Install YJ connector. Pull
test connector 25K. Break down lubricator. Stand back injector. Install night cap. Stage mud motor for P/U. Return to camp.
Plan forward: Run YJ 3.75" mill & motor to clear well. Displace kill fluid w/ FW. Run HES CBL tool.
9/13/2023 Fox Energy, YJ & Cruz PJSM & permit. Travel to Lewis River.,On location. Fire equipment. P/U injector head & 3 sections lubricator. M/U YJ BHA. PT BHA 3000
PSI. Test good.,RIH w/ YJ BHA consisting of: 1.75 x 2-3/8 CTC / Dual Flapper Check Valve / Bi-Di-Jar / Hyd Disco (3/4 ball) / Dual Acting Crc Sub (5/8 ball) / 2.88
OD Mud Motor / X-over 2-3/8 PAC x 2-3/8 REG / Hilcorp owned Tri-Cone Bit 3.75 OD.,P/U weight at 6700 24K. Dry tag cement stringer 6790. P/U 20. Kick on
pump at 1.4 BPM at 3300 PSI. Go back down and mill through small bridge at 6790. Continue down hole slowly. At 7000 back pump off to 1 BPM at 1800 PSI.
Continue down hole and tag fill at 7270 (PBTD 7275).,P/U 10. Kick pumps to 2 BPM at 3450 PSI to bottoms up and displace kill fluid w/ FW while POOH.,OOH.
Break down YJ BHA. Cut off YJ CT connector. Install Fox crimp on connector. HES on location setting up CBL memory gauge.,RIH w/ HES CBL memory gauge
at 100 FPM to 7260. Stand by for tools to engage.,POOH logging at 40 FPM.,Made 5 minute stop for marker at 2600. Continue POOH.,OOH. Lay down HES CBL
tools. Lay down lubricator, stand back injector head & night cap BOPs. SDFN. Return to camp.
Plan forward: Blow down well w/ N2.
9/14/2023 Fox Energy & Cruz PJSM & permit. Travel to Lewis River.,Fire equipment. P/U injector head & 3 sections lubricator. M/U 2-1/2 reverse jet nozzle.,RIH w/ 2-1/2
reverse jet nozzle at 70 FPM.,At 4700 went online w/ N2 at 500 scfs. Continue down hole.,At 6000 kicked rate up to 1000 scfs at 2000 PSI.,Tag fill at 7274 (PBTD
7275). P/U weight 25K. Injecting 1000 scfs at 2400 PSI.,N2 to surface. 125 BBLs recovered. POOH.,OOH. Left 1900 PSI N2 cap on well in preparation for
perforating. R/D & move majority of CT / N2 equipment to IRU 41-01. Secure equipment. SDFN. Return to camp.
9/15/2023 AK E-Line PJSM & permit. Travel to Lewis River. Trailer guns for job to Lewis River. MIRU.,MIRU AK E-Line.,PT surface equipment 250 / 3000 PSI. Test
good,,Opened well. 1600 PSI of N2 cap. This was supposed to be 2000 PSI. N2 truck broke down yesterday leaving 1900 PSI. 1600 PSI not sufficient
overbalance.,Picked up pea shooter 2 x 3 gun. In mean time RIH w/ current gun just to make tie in pass.,Made tie in pass. Sent to town. Town adjusted by
dropping 5 down. POOH.,OOH. L/D un-shot gun. P/U 2 x 3 pea shooter gun.,RIH w/ 2 x 3 pea shooter. Target 6817 to 6820 in Tyonek T13 zone. CCL to TS =
18.7 / CCL to be at 6798.3 to place TS at 6817.,Position pea shooter. Fire gun. POOH. Start PSI: 1591 / 5 Min 1591 / 10 Min 1590 / 15 Min 1588,OOH. L/D pea
shooter. End cap dry. P/U Gun ONE.,RIH w/ 2-3/4 x 13 Gun ONE. Target 6806 to 6819 in Tyonek T13 zone. CCL to TS = 9 / CCL to be at 6797 to place TS at
6806.,Position Gun ONE. Fire Gun ONE. POOH. Start PSI: 1582 / 5 Min 1584 / 10 Min 1581 / 15 Min 1580,OOH. L/D Gun ONE. End cap dry. P/U Gun TWO.,RIH
w/ 2-3/4 x 5 Gun TWO. Target 6795 to 6800 in Tyonek T13 zone. CCL to TS = 14 / CCL to be at 6781 to place TS at 6795.,Position Gun TWO. Fire Gun TWO.
POOH. Start PSI: 1576 / 5 Min 1576 / 10 Min 1576 / 15 Min 1575,OOH. L/D Gun TWO. End cap dry. P/U Gun THREE.,RIH w/ 2-3/4 x 14 Gun THREE. Target
6763 to 6777 in Tyonek T13 zone. CCL to TS = 9 / CCL to be at 6754 to place TS at 6763.,Position Gun THREE. Fire Gun THREE. POOH. Start PSI: 1568 / 5
Min 1572 / 10 Min 1570 / 15 Min 1568,OOH. L/D Gun THREE. End cap dry. Secure equipment. Night cap BOP. Turn well over to production to test over night.
SDFN.,Return to camp
Plan forward: Perforate Tyonek T12 zone after well test.
9/16/2023 AK E-Line PJSM & permit. Gather tools at connex. Travel to Lewis River.,Rig back on to well.,RIH w/ GPT. Tag fill at 7271 (PBTD 7275). Found FL at 7140.
Surface Tbg PSI 1145. POOH,OOH. L/D GPT. Set up CIBP. P/U CIBP & run tool.,RIH w/ 4-1/2 (3.71 OD) CIBP. Target depth 6760. CCL to top CIBP = 13.2 /
CCL to be at 6746.8 to place top of CIBP at 6760.,Position CIBP. Fire setting tool. Good weight drop. P/u hole then go back down and tag CIBP on depth at 6760.
POOH.,OOH. L/D CIBP setting tool. P/U 2 x 3 Pea Shooter.,RIH w/ 2 x 3 pea shooter. Target 6727 to 6730. CCL to TS = 7.6 / CCL to be at 6719.4 to place TS at
6727.,Position pea shooter. Fire gun. POOH. Start PSI: 1106 / 5 Min 1104 / 10 Min 1104 / 15 Min 1101.,OOH. L/D Pea Shooter. P/U Gun FOUR.,RIH w/ 2-3/4 x
20 Gun FOUR. Target 6737 to 6757 in Tyonek T12 zone. CCL to TS = 9 / CCL to be at 6728 to place TS at 6737.,Position Gun FOUR. Fire Gun FOUR. POOH.
Start PSI: 1091 / 5 Min 1091 / 10 Min 1090 / 15 Min 1089,OOH. L/D Gun FOUR. End cap damp. P/U Gun FIVE.,RIH w/ 2-3/4 x 13 Gun FIVE. Target 6724 to 6737
in Tyonek T12 zone. CCL to TS = 9.8 / CCL to be at 6714.2 to place TS at 6724.,Position Gun FIVE. Fire Gun FIVE. POOH. Start PSI: 1076 / 5 Min 1076 / 10 Min
1074 / 15 Min 1072,OOH. L/D Gun FIVE. End cap dry. Secure equipment. Night cap BOP. Turn well over to production to test over night. SDFN.,Return to camp.
Plan forward: GPT and possibly set CIBP if well test not satisfactory.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
LRU C-002
Lewis River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00065 LRU C-02 Completion
Spud Date:
9/17/2023 AK E-Line PJSM & permit. Travel to Lewis River.,Rig back on to well.,RIH w/ GPT. Tag CIBP at 6760. Found FL at 6700. Surface Tbg PSI 251. POOH.,OOH. L/D
GPT. P/U 3.71 OD CIBP.,RIH w/ 4-1/2 (3.71 OD) CIBP. Target depth 6699. CCL to top CIBP = 13.2 / CCL to be at 6685.8 to place top of CIBP at 6699.,Position
CIBP. Fire setting tool. Good weight drop. P/u hole then go back down and tag CIBP on depth at 6699. POOH.,OOH. L/D CIBP setting tool. P/U 2-3/4 x 9 Gun
SIX. Fox N2 MIRU to companion wing valve. X-fer N2 tank to pump.,PT Fox N2 2000 PSI. Test good.,Inject N2 at 1000 scfs. Pressured up from 250 to 1900
PSI.,RDMO Fox N2. RIH w/ 2-3/4 x 9 Gun SIX. Target 6586 to 6595 in Tyonek T11 zone. CCL to TS = 14.8 / CCL to be at 6571.2 to place TS at 6586.,Position
Gun SIX. Fire Gun SIX. POOH. Start PSI: 1875 / 5 Min 1875 / 10 Min 1873 / 15 Min 1870,OOH. L/D Gun SIX. End cap dry. P/U Gun SEVEN.,RIH w/ 2-3/4 x 13
Gun SEVEN. Target 6563 to 6576 in Tyonek T11 zone. CCL to TS = 9.8 / CCL to be at 6553.2 to place TS at 6563.,Position Gun SEVEN. Fire Gun SEVEN.
POOH. Start PSI: 1853 / 5 Min 1854 / 10 Min 1851 / 15 Min 1847,OOH. L/D Gun SEVEN. End cap dry. Secure equipment. Night cap BOP. Re-head. Turn well
over to production to test over night. SDFN.,Return to camp.
Plan forward: GPT log and determine from results.
9/18/2023 AK E-Line PJSM & permit. Travel to Lewis River.,Rig back on to well.,RIH w/ GPT. Tag CIBP at 6699. Found FL at 6640. Surface PSI 1012. POOH.,L/D GPT.
P/U 2 x 3 Pea Shooter.,RIH w/ 2 x 3 Pea Shooter. Target 6346 to 6349. Tyonek T8A zone. CCL to TS = 7.6 / CCL to be at 6338.4 to place TS at 6346.,Position
Pea Shooter. Fire gun. POOH. Start PSI: 994 / 5 Min 994 / 10 Min 993 / 15 Min 992.,OOH. L/D Pea Shooter. P/U Gun EIGHT.,RIH w/ 2-3/4 x 18 Gun EIGHT.
Target 6338 to 6356 in Tyonek T8A zone. CCL to TS = 10.8 / CCL to be at 6327.2 to place TS at 6338.,Position Gun EIGHT. Fire Gun EIGHT. POOH. Start PSI:
988 / 5 Min 991 / 10 Min 990 / 15 Min 989,OOH. L/D Gun EIGHT. Pad Op on location. Start bleeding N2 cap off of well from 987 to 787. Built to 792 in one
hour.,Bleed an additional 200 PSI to 595. Built to 599 in one hour.,Bleed an additional 200 PSI to 399. 399 PSI stable for one hour.,RIH w/ GPT. Pad Op dong
final bleed down to 201 PSI from 399. No cooling effect seen at perfs. Initial FL at 6590. Final FL after bleed down was 6580. POOH.,OOH. L/D GPT. P/U
CIBP.,RIH w/ 4-1/2 (3.71 OD) CIBP. Target depth 6320. CCL to top CIBP = 13.2 / CCL to be at 6306.8 to place top of CIBP at 6320.,Position CIBP. Fire setting
tool. Good weight drop. P/U hole then go back down and tag CIBP on depth at 6320. (Collar at 6310) POOH.,OOH. L/D CIBP setting tool. Secure equipment.
Night cap BOP. SDFN.,Return to camp.
Plan forward: N2 in morning to pressure up 1800-2000 PSI. Perf T7 zone.
9/19/2023 AK E-Line PJSM & permit. Travel to Lewis River.,MIRU Fox N2.,PT 250 / 2000 PSI. Test good.,Start PSI 200. Inject N2 at 800 scfs. Pressure up to 1000 PSI. S/D
N2.,RDMO Fox N2. AK E-Line rig back on well.,RIH w/ 2-3/4 x 9 Gun NINE. Target 6249 to 6258 in Tyonek T7 zone. CCL to TS = 9.8 / CCL to be at 6239.2 to
place TS at 6249.,Position Gun NINE. Fire Gun NINE. POOH. Start PSI: 1008 / 5 Min 1010 / 10 Min 1010 / 15 Min 1007,OOH. L/D Gun NINE. Dry end cap. P/U
Gun TEN.,RIH w/ 2-3/4 x 6 Gun TEN. Target 6240 to 6246 in Tyonek T7 zone. CCL to TS = 14 / CCL to be at 6226 to place TS at 6240.,Position Gun TEN. Fire
Gun TEN. POOH. Start PSI: 1003 / 5 Min 1003 / 10 Min 1002 / 15 Min 1002,OOH. L/D Gun TEN. Dry end cap. P/U GPT. Pad Op on location prepping well for
flow test.,Pad Op slowly bleeding off well from 1000 PSI.,At 600 PSI still bleeding off. RIH w/ GPT.,No cooling effect seen at perfs. Pad Op SI well flow at 200 PSI.
FL at 6300. CIBP at 6320. POOH.,OOH. L/D lubricator. Nite cap BOP. Secure well for 18:00 AK E-Line change out.
Plan forward: Possible CIBP or continue on perf T6 zone.
9/20/2023 PJSM, Discuss daily operations wireline and N2 activities,Crew travel to location,PIck up lubricator & test to 2000 psi good, pick up GPT & run in hole, Open well.
casing pressure-268 psi
*Fluid level @ 6290'
Pull out of hole with GPT,Make up 3.71" OD plug & run in hole to setting depth 6220' CCL @ 6206.2'. Set plug & pull out of hole.,Pick up & make up 2-3/4" x 15'
barrel (13 foot loaded, 6 shots per foot, 60 degree, 15 grams, .39" holes) CCL-TS=9.75', CCL set @ 6178.2'
Pressure up to 1200 psi as per engineer with N2 (632 gal/ 44891 scf's)
Run in hole to 6178.2' @ CCL
Perf from 6188' to 6201' Tyonek T6 formation
Pull out of hole
Monitor psi starting pressure 1207psi 5 min @ 1208, 10 min @ 1208, 15 min @ 1204,Pick up & make up 2-3/4" x 15' barrel (14 foot loaded, 6 shots per foot, 60
degree, 15 grams, .39" holes) CCL-TS=9', CCL set @ 6143'
Wellhead pressure 1190.
Run in hole to 6143' @ CCL
Perf from 6152' to 6166' Tyonek T6 formation
Pull out of hole
Monitor psi starting pressure-1190, psi @ 5 min @ 1192, 10 min @ 1190, 15 min @ 1186,Pick up & make up 2-3/4" x 21' barrel (20 foot loaded, 6 shots per foot,
60 degree, 15 grams, .39" holes) CCL-TS=9', CCL set @ 6094'
Wellhead pressure 1181.
Run in hole to 6094' @ CCL
Perf from 6103' to 6122' Tyonek T6 formation
Pull out of hole
Monitor psi, starting pressures- 1175, 5 min @ 1177, 10 min @ 1175, 15 min @ 1173,Lay down lubricator & secure well. Hand over to production.
9/21/2023 PJSM, Discuss daily operations logging & wireline work.,Crew travel to location, Check wellhead pressures SITP-444 psi ,Start & warm up equipment, Pick up
lubricator, Make up GPT, Make up lubricator to Eline bop & pressure test 2000 psi-good.,Run in hole to 6195', Perform GPT- send logs to town confirm no fluid
level, Pull out of hole & remove lubricator,Run to storage for barrel & shape charges, Build gun on location,Pick up lubricator & 2-3/4" x 21' Barrel (20' loaded, 6
shots/ft, 15 gram, 37.95" penetration, .39 holes, total shots 120) & run in hole to depth CCL to TS=9
Correlate & correct as per Geo.-good.
Operator bleed down casing pressure to 200 psi.
Set CCL on Depth @ 6094' to Perf from 6103' to 6122'
Monitor Wellhead pressures starting 200 psi, 5 min @ 211, 10 min @ 216, 15 min @ 219
Pull out of hole,Shut in & secure well, Lay down lubricator & check guns all fired & dry.
Turn over to operator
9/22/2023 PJSM, Discuss daily operations with Sim ops.,Crew travel to location,Pump methanol down casing 700 gal.,Pressure up to 3500 psi, slight breakover @ 2950 but
continued to build to 3500 psi. Shut in & monitor pressure overnight.,Shut in & secure well
9/24/2023 PJSM, Discuss daily operations, rig down, rig up and logging runs,Crew travel to location,Rig down on IRU 41-01,Mobili ze equipment to location, Spot in & rig
up,Pick up & make up lubricator with GPT/GAMMA/CCL
Pressure test lubricator to 250 low/ 3000 high-good
Run in hole with logging tools
Fluid level @ 4696', Tag bottom @ 6167'
Pull up hole to correlate
Pressure up wellbore to 1500 psi
Monitor water drop with GPT
200 ft drop in 20 min
Pressure up to 2200 & pull out of hole
Shut in & secure well,Trouble shoot unit generator
9/25/2023 PJSM, Discuss daily wireline operations,Crew travel to location,Work on wireline unit & generator-test good,Pick up & make up 3.71" plug, Make up lubricator &
test-good,
Run in hole & tag @ 6114' & correlate- on depth
Set plug @ 6078', Tag & Pull out of hole,Pick up 2-3/4" x 11' barrel (10' loaded, 6 spf, 22.3 grams, 60 deg offset, Total: 60 shots)
Corelate log & check-good. CCL-TS-9', Set CCL @ 5996', Perf f/ 6005' to 6015'
Starting psi: 1300, psi @ 5 min-1299, psi @ 10 min 1296, psi @ 15 min 1292
Pull out of hole
Shut in & secure well
:,Rig down equipment & mob to BRU 241-23
9/28/2023 PJSM,Arrive at k pad start and warm up equipment, depart k pad go fuel up and enroute to Lewis River,Arrived at Lewis River C-02 well, spot equipment and
rehead, check tools, arm, stab, on lubricator.,Waiting on Triplex pump. Triplex arrived, pressure test lubricator to 250 low and 2500 psi good test.,Open well Rih
with F/n, gun gamma, shock sub, 2-3/8 gun loaded with 20' of 6 spf, 60* phasing, total shots 240 overall length 32 ft. max OD 3.125, make correlation pass from
6078 ft. ELM to 4000 ft. wait on approval make pass spot gun on depth, pref at 5564 ft. to 5584 ft. pooh initial pressure 1260 psi, after perfing pressure.1137
psi.,Lay down and change out guns.,Open well Rih with F/n, gun gamma, shock sub, 2-3/8 gun loaded with 20' of 6 spf, 60* phasing, total shots 240 overall length
32 ft. max OD 3.125, make correlation pass send in for approval, wait on approval, make pass spot gun on depth, pref the Beluga L4 sand from 5300 to 5320 ft.
Initial pressure reading 1103 psi 5 minutes 1104 psi, to minute 1103 psi, 15-minute reading 1101 psi pooh.,Out of hole lay down guns all shots fired, Bull plug dry,
lay down lubricator..,travel to shop.
9/29/2023 PJSM depart camp,Enroute to well site, start up and warm up equipment.,Check tools, arm guns stab on well, RIH with F/N, gun gamma, shock sub, 2-3/8 gun
loaded with 10 ft of 6 spf, 60* phasing, OAL 22' max OD, 3.125, Run correlation log from 5100 ft to 4974 ft. send in for correlation, Perf the Beluga J sand from
4984 ft to 4994' initial pressure 1249 psi 5-minute reading 1251 psi, 10 minute, 1250 psi, 15 minute 1251 psi pooh, all shots fired, bull plug dry,,Set up second
gun, check tools, arm gun, stab on well, RIh with F/N, gun gamma, shock sub 2-3/8 10'-gun load 6 spf, 60* phasing OAL 22 ft. max OD 3.125, run correlation pass
f/ 5050 ft. to 4759 ft. send for correlation, perf the Beluga I-12 sand from 4924 ft to 4934 ft, Initial pressure 1266 psi, 5 minutes 1294 psi, 10-minute 1334 ft. 15-
minute 1373 ft. pooh, tbg pressure at 1545 psi, gun is dry.,Production bleeding N2 off well LEL over range at 1326 FTP put C-002 in sales at 1520 hrs. at 1406
hrs.' rate at 696 mcfd, FTP 1196 PSI,check tools, arm gun, stab on well, RIh with F/N, gun gamma, shock sub 2-3/8 12'-gun load 6 spf, 60* phasing OAL 22 '. max
OD 3.125, run correlation pass f/ 4877 ft. to 4742 ft. send for correlation, perf the Beluga I-8 sand f/ 47544 ft to 4766 ft, Initial FTP 1077 psi, 5 minutes 1083 psi,
10-minute 1085 ft. 15-minute 1088 ft. pooh, tbg pressure at 1093 psi, gun is dry. Rate increase f/ 610 mcf to 782 mcf No water, Pooh,lay down lubricator depart to
camp
9/30/2023 PJSM, travel to well site, startup & warm up equipment, stab on well open swab,RIH with F/N, Gun Gamma, shock sub, 2-3/8 gun loaded with 20 ft. 6 spf , 60*
phasing, (OAL 32 ft. max OD 3.125) production flowing well to target FTP AT 1000 PSI, current rate at 2.1 mmcfd/ FTP 1130 psi, no water rate at 1.1 mmcfd/ FTP
stabilized at 1000 psi, send log in for correlation. Perf the I8 sand from 4778 ft. to 4798 ft. Initial FTP at 1011 psi 5-minute 1015 psi, 10-minut 1016 psi, 15-minute
1017 psi pooh rate,at 1.2 mmcfd/FTP 1024 PSI NO WATER all shots fired; bull plug dry.,OOH l/d guns make up gun #2 stab on, open well, RIH with F/n, gun
gamma, shock sub, 2-3/8 gun load with 20 ft. 6 spf, 60^ phasing, OAL 32 FT. MAX OD 3.125, make correlation pass, f/ 4920 ftp 4607 send in for correlation per
the I8 sand f/ 4758 ft. to 4778 ft. Initial FTP at 1036 psi 5-minute 1038 FTP, 10-minute 1039 FTP, 15 - minute 1040 FTP POOH, OOH FTP AT 1054 LAY down
gun all shots fired, bull plug dry,,Rig down equipment, refuel.,Travel to k pad
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6 C 6 C
C
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.08.28 11:13:17 -08'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.08.28 13:19:31 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
80
Yes X No X Yes No 6
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Type I II 708 2.45
Type I II 314 1.16
5
23.88
Casing Hanger 16 TXP BTC Cactus 1.38 23.88 22.50
3,105.99 27.88
Casing Pup Joint 9 5/8 47.0 L-80 TXP BTC Tenaris 4.00 27.88
1.33 3,107.32 3,105.99
Casing 9 5/8 47.0 L-80 TXP BTC Tenaris 3,078.11
Float Collar 10 3/4 BTC Innovex
One 11 5/8" OD x 10" tall composite centralizer every other joint, up to 300'
Casing 9 5/8 47.0 L-80 TXP BTC Tenaris 77.68 3,185.00 3,107.32
www.wellez.net WellEz Information Management LLC ver_04818br
5
Type of Shoe:Innovex Bullnose Casing Crew:Parker TSM
12 322
3,186.583,195.00 3,105.99
CEMENTING REPORT
Csg Wt. On Slips:
Spud Mud
12:30 8/6/2023 25
15.8 62
Bump press
Returns at Surface
Bump Plug?
228/227.34
1290
131
Halliburton
FI
R
S
T
S
T
A
G
E
10.5Tuned Spacer 59
10 4.9
70
850
Csg Wt. On Hook: Type Float Collar:Innovex No. Hrs to Run:12
BTC Innovex 1.58 3,186.58 3,185.00
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.LRU C-002 Date Run 5-Aug-23
CASING RECORD
County State Alaska Supv.R Pederson / J Richardson
3,105.99
Floats Held
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG10
Shoe @ 3186.58 FC @ Top of Liner
Casing (Or Liner) Detail
Float Shoe 10 3/4
TD Shoe Depth: PBTD:
Jts.
1
1
135
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:
Casing (Or Liner) Detail
Shoe 5
Rotate Csg Recip Csg Ft. Min. PPG10.2
Shoe @ 7431.17 FC @ Top of Liner 3000.69
Floats Held
6% KCL Polymer
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.LRU C-002 Date Run 24-Aug-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Summit 1.55 7,341.10 7,339.55
Csg Wt. On Hook: Type Float Collar:Summit No. Hrs to Run:22
10.2 5
81
1220
FI
R
S
T
S
T
A
G
E
10.5Tuned Prime 30
104/106
1700
0
Halliburton
15.3 38
Bump press
CBL
Bump Plug?
4:21 8/25/2023 3180'
7,341.107,501.00 7,275.24
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL mud
12 361
Type of Shoe:Summit Bullnose Casing Crew:Parker
Baker HRD-E ZXP/Flex-Lock V
www.wellez.net WellEz Information Management LLC ver_04818br
4
One every other joint for a total of 67 spiral type hydro-forms
Liner 4 1/2 12.6 L-80 JFE JFE Lion 31.11 7,339.55 7,308.44
Float Collar 5 BTC Summit 1.05 7,308.44 7,307.39
Liner 4 1/2 12.6 L-80 JFE JFE Lion 31.07 7,307.39 7,276.32
Landing Collar 5 BTC JHOBBS 1.08 7,276.32 7,275.24
Liner 4 1/2 12.6 L-80 JFE JFE Lion 4,237.16 7,275.24 3,033.08
Pup Joint 4 1/2 12.6 L-80 JFE JFE Lion 4.68 3,038.08 3,033.40
Liner Hanger 8 5/8 JFE Baker 31.09 3,033.40 3,005.69
l ll 845 2.39
l ll 181 1.24
5
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/04/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231004
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
IRU 41-01 50283200880000 192109 9/17/2023 HALLIBURTON Coilflag
KBU 32-06 50133206580000 216137 9/8/2023 HALLIBURTON PPROF
LRU C-02 50283201900000 223057 9/13/2023 HALLIBURTON RBT
MPU E-37 50029236160000 218158 9/24/2023 READ Caliper Survey
MPU F-53A 50029225780100 213136 9/27/2023 READ Caliper Survey
MPU F-79 50029228130000 197180 9/26/2023 READ Caliper Survey
MPU L-57 50029236090000 218072 9/26/2023 READ Caliper Survey
MPU S-06 50029231630000 203109 9/29/2023 READ Caliper Survey
MPU B-32 50029235700000 216151 9/12/2023 HALLIBURTON Perf
TBU K-09 50733201100000 1068038 10/1/2023 READ Caliper Survey
Please include current contact information if different from above.
T38028
T38029
T38030
T38031
T38032
T38033
T38034
T38035
T38036
T38037
10/4/2023
LRU C-02 50283201900000 223057 9/13/2023 HALLIBURTON RBT
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.10.04
13:03:04 -08'00'
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Sierra Becia; John Salsbury
Subject:RE: LRU C-02 (PTD 223-057) (Sundry 323-482) - Request to add sands to sundry
Date:Thursday, September 28, 2023 5:18:00 PM
Attachments:image005.png
image006.png
image007.png
image008.png
Jake,
Hilcorp has approval to proceed with the additional requested perfs below. Perforating above 3870’ TVD
is not allowed at this time.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <jake.flora@hilcorp.com>
Sent: Thursday, September 28, 2023 2:55 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Sierra Becia <Sierra.Becia@hilcorp.com>; John Salsbury <jsalsbury@hilcorp.com>
Subject: LRU C-02 (PTD 223-057) (Sundry 323-482) - Request to add sands to sundry
Hi Bryan,
We are testing our way uphole and have yet to establish production.
Below is a look at what we have done in the wellbore. Hilcorp requests to raise the top of the
approved perf interval to 3870’ TVD. Please let me know if you would like to see anything
additional.
Thanks,
Jake
Deepest Open Perf: 5599’ TVD T5 (6005-6016’ MD (5588-5599’ TVD)
New MPSP 2352 psi
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
New shallowest allowable perf calculated 3782’ TVD
Requested new shallowest perf requested 3870’ TVD (4264’ MD, top of the Beluga H16)
TOC at 3180’ (9-15-23 CBL)
Current perforations:
6078’ CIBP
6103’ – 6201’ T6 perfs (gross interval shot)
6220’ CIBP
6240 – 6246’ T7
6249 – 6258’ T7
6320’ CIBP
6338 – 6356’ T8
6346 – 6349’ T8
6563 – 6576’ T11
6586 – 6595’ T11
6699’ CIBP
6724 – 6737’ T12
6737 – 6757’ T12
6760’ CIBP
6763 – 6777’ T13
6795 – 6800’ T13
6806 – 6819’ T13
Current Sundry Interval:
Requested to Add:
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, September 15, 2023 10:51 AM
To: Jacob Flora <jake.flora@hilcorp.com>
Subject: RE: [EXTERNAL] LRU C-04 RBT PASS
Jake,
CAUTION: This email originated from outside the State of Alaska mail system. Do
not click links or open attachments unless you recognize the sender and know the
content is safe.
Hilcorp has approval to proceed with the perfs per sundry 323-482.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <jake.flora@hilcorp.com>
Sent: Friday, September 15, 2023 7:50 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>
Subject: FW: [EXTERNAL] LRU C-04 RBT PASS
Hello Bryan,
Please see attached CBL and screenshots below. The TOC is just below the liner top. Let me know if you
agree, we are perforating soon.
Greatly appreciated,
Jake
(Image on next page)
From: John Wendell Soules III <John.SoulesIII@halliburton.com>
Sent: Friday, September 15, 2023 6:26 AM
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
To: Jacob Flora <jake.flora@hilcorp.com>
Cc: Eric Vela <Eric.Vela@halliburton.com>
Subject: [EXTERNAL] LRU C-04 RBT PASS
Jake,
I attached the uncorrected pass pdf & LAS. TOC is showing @ 3170’ (UNCORRECTED). Can you have the
Geologist look and give me a correction?
Thanks,
John W Soules III
General Integrated Cased Hole Field Professional
Sterling District EIC
Sterling, Alaska
Email: john.soulesiii@halliburton.com
Mobile: (432) 212-2230
Office: (907) 273-3501
Anchorage: (907) 275-2600
This e-mail, including any attached files, may contain confidential and privileged information for the sole
use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited.
If you are not the intended recipient (or authorized to receive information for the intended recipient),
please contact the sender by reply e-mail and delete all copies of this message.
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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual
or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any
dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by
return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward
transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted
by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do
not click links or open attachments unless you recognize the sender and know the
content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: [EXTERNAL] LRU C-04 RBT PASS
Date:Friday, September 15, 2023 10:50:00 AM
Attachments:image005.png
image006.png
image007.png
Jake,
Hilcorp has approval to proceed with the perfs per sundry 323-482.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <jake.flora@hilcorp.com>
Sent: Friday, September 15, 2023 7:50 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Chad Helgeson <chelgeson@hilcorp.com>
Subject: FW: [EXTERNAL] LRU C-04 RBT PASS
Hello Bryan,
Please see attached CBL and screenshots below. The TOC is just below the liner top. Let me know if you
agree, we are perforating soon.
Greatly appreciated,
Jake
From: John Wendell Soules III <John.SoulesIII@halliburton.com>
Sent: Friday, September 15, 2023 6:26 AM
To: Jacob Flora <jake.flora@hilcorp.com>
Cc: Eric Vela <Eric.Vela@halliburton.com>
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Subject: [EXTERNAL] LRU C-04 RBT PASS
Jake,
I attached the uncorrected pass pdf & LAS. TOC is showing @ 3170’ (UNCORRECTED). Can you have the
Geologist look and give me a correction?
Thanks,
John W Soules III
General Integrated Cased Hole Field Professional
Sterling District EIC
Sterling, Alaska
Email: john.soulesiii@halliburton.com
Mobile: (432) 212-2230
Office: (907) 273-3501
Anchorage: (907) 275-2600
This e-mail, including any attached files, may contain confidential and privileged information for the sole
use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited.
If you are not the intended recipient (or authorized to receive information for the intended recipient),
please contact the sender by reply e-mail and delete all copies of this message.
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.
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
Date: 09/15/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
MUDLOGS - EOW DRILLING REPORTS (07/31/2023 to 08/20/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log
Drilling Dynamics Log
SFTP Transfer - Main Folder Contents:
Please include current contact information if different from above.
PTD: 223-057
T37998
9/18/2023
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.09.18
09:56:29 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/07/2022
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: LRU C-02
PTD: 223-057
API: API 50-283-20190-00-00
LeakPoint Survey (8/29/23)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-057
T37980
9/7/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.09.07
10:36:57 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/06/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
FINAL LWD FORMATION EVALUATION LOGS (07/30/2023 to 08/28/2023)
x ROP, AGR, EWR-M5, ALD, CTN, BaseStar, ResiStar, LithoStar (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-057
T37978
9/7/2023
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.09.07
08:57:19 -08'00'
1
Regg, James B (OGC)
From:Rance Pederson - (C) <rpederson@hilcorp.com>
Sent:Saturday, September 2, 2023 12:49 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT Test Report
Attachments:MIT Hilcorp 147 09-02-23.xlsx; MIT Chart_LRU C-02_9-2-23.pdf
Please see the aƩached MIT test results for LRU C‐02 on Hilcorp Rig 147.
Rance Pederson
Drilling Foreman
Lewis River Unit
907‐776‐6776
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Lewis River Unit C-02PTD 2230570
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230570 Type Inj N Tubing 0 3680 3680 3680 Type Test P
Packer TVD 2639'BBL Pump 0.9 IA 0 480 480 480 Interval O
Test psi 3680 BBL Return 0.9 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230570 Type Inj N Tubing 0 400 400 400 Type Test P
Packer TVD 2639'BBL Pump 2.0 IA 0 3100 3100 3100 Interval O
Test psi 3100 BBL Return 2.0 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:9 5/8" x 4 1/2" annulus. DHL retrievable packer set at 2962' md/2639' tvd. Post completion test as per PTD. AOGCC witness waived
Notes:
Notes:
Hilcorp Alaska, LLC
Beluga River Field / Lewis River Unit / C Pad
Rance Pederson
09/02/23
Notes:4 1/2" completion string down to packer. DHL retrievable packer set at 2962' md/2639' tvd. Post completion test as per PTD. AOGCC witness waived
Notes:
Notes:
Notes:
LRU C-02
LRU C-02
Form 10-426 (Revised 01/2017)2023-0902_MITP_LRU_C-02_2tests
jbr; 10/30/2023
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Date:Thursday, August 31, 2023 4:46:00 PM
Sean,
Hilcorp has authorization to reduce the IA test pressure to 3000 psi based on the lower MPSP.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 4:43 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Bryan,
I’ve learned that the 9-5/8’ x 4-1/2” packer going in hole on LRU-C2 on is a shear to release packer
and a 3500 psi may be pushing the force envelop. The vendor is looking into in.
I’d like to request to reduce the IA test pressure from 3500 psi to 3000 psi. The justification is that
we did not drill to our planned TD and have a lower then planned MASP.
Shoe depth – 7341’ MD and 6909’ TVD
Bottom perforation – 6850’ MD
10 PPG formation
BHP=3593 psi (shoe)
MASP = 2902 psi
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 31, 2023 11:09 AM
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Sean,
Hilcorp has authorization to proceed with the planned changes.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:34 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
The top of the PBR is a 3001’. We will have a WLEG, X nip, and full joint below the packer. Packer
depth will be around 2940’.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 31, 2023 10:16 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Sean,
Thanks for the notification. What’s the approximate planned depth for the production packer?
Regards
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.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:01 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: LRU-C2 (223-057) Upper completion change
Bryan,
After running the tie-back on LRU-C2 the IA and tubing failed to test. Both slickline and eline ran leak
detection logs and the leak point was not conclusively identified. The completion was pulled and
rerun with replacement equipment. The tubing now leaks while the IA holds solid indicating a
potential problem with the PBR. We will swap the seal stem for a production packer. There are no
changes to the planned test pressures.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of 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.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Date:Thursday, August 31, 2023 11:08:00 AM
Sean,
Hilcorp has authorization to proceed with the planned changes.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:34 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
The top of the PBR is a 3001’. We will have a WLEG, X nip, and full joint below the packer. Packer
depth will be around 2940’.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 31, 2023 10:16 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Sean,
Thanks for the notification. What’s the approximate planned depth for the production packer?
Regards
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.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:01 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: LRU-C2 (223-057) Upper completion change
Bryan,
After running the tie-back on LRU-C2 the IA and tubing failed to test. Both slickline and eline ran leak
detection logs and the leak point was not conclusively identified. The completion was pulled and
rerun with replacement equipment. The tubing now leaks while the IA holds solid indicating a
potential problem with the PBR. We will swap the seal stem for a production packer. There are no
changes to the planned test pressures.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, CTCO, N2
2.Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6.API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,096'7,358' (TOF)
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,760psi
Intermediate
Production
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
N/A N/A
6,664'7,358'6,921'
Lewis River Lewis River Undefined Gas
16"
9-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Lewis River Unit (LRU) C-02Statewide Spacing
Same
~2,684 psi N/A
Length
September 8, 2023
N/A
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,870psi
120'120'
3,185'
Size
120'
3,185'
MD
Hilcorp Alaska, LLC
Proposed Pools:
N/A
TVD Burst
N/A
2,835'
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
ADL 058798
223-057
50-283-20190-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
Ot
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 11:30 am, Aug 25, 2023
323-482
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.08.25 10:02:19 -
08'00'
Noel Nocas
(4361)
X
MDG 8/31/2023
Submit CBL to AOGCC and obtain approval to proceed before perforating.
BOP test to 3000 psi.
10-407
BJM 9/5/23 DSR-8/28/23*&: JLC 9/5/2023
09/05/23
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.09.05
21:30:41 -08'00'
RBDMS JSB 090823
Well Prognosis
Well Name: LRU C-02 API Number: 50-283-20190-00-00
Current Status: Gas Producer Permit to Drill Number: 223-057
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O)
Maximum Expected BHP: 3323 psi @ 6392’ TVD (Based on 0.52 psi/ft gradient))
Max. Potential Surface Pressure: 2684 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
LRU C-02 2023 grass roots well targeting the Beluga and Tyonek sands. The objective of this sundry is to clean
out the liner with coil tubing/nitrogen and perforate/test multiple Beluga and Tyonek sands. All sands lie in the
Lewis River Undefined Gas Pool.
Wellbore Conditions:
Drilling will leave the cemented liner full of drilling mud, with the tubing and annulus displaced to KCL, and
pressure tested.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 3000 psi.
4. Clean out wellbore to TD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, log CBL submit CBL for review
6. RIH, reverse out wellbore with nitrogen, trap ~2200 psi on wellbore
7. RDMO coil tubing
8. RU E-line, PT lubricator to 3000 psi
9. Perforate and test Beluga sands within the below interval from the bottom up:
Top Beluga I10 4836’ MD / 4435’ TVD
Bottom Tyonek 13 6820’ MD / 6392’ TVD
a. All depths are + / -
b. Use nitrogen as needed for fluid depression if a wet zone is encountered
c. If any zone produces sand and/or water or needs isolated, RU E-line, PT lubricator to 3000 psi,
set plug above the perforations OR patch across the perforations.
d. Frac Calcs: Using 13.9 ppg EMW FIT at the surface casing shoe (0.722 psi/ft frac grad)
e. Shallowest Allowable Perf TVD = MPSP/(0.722-0.1) = 2684 psi / 0.622 = 4316‘ TVD
10. RDMO
11. Turn well over to production & flow test well
perforate/test multiple Beluga and Tyonek sands.
Well Prognosis
Attachments:
1. Current Planned Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
5. AOGCC RWO Change Form
Updated by CJD 8.24.2023
CURRENT PLANNED
SCHEMATIC
Lewis River Unit
LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
PBTD= ±7,257’ MD / TVD = ±6,822’
TD = 7,501 MD / TVD = ±7,070’
RKB to GL = 18.5’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 3,186’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,999’ 7,337’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 3,023’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 3,023’ 6.151” 8.540” Liner hanger / LTP Assembly
2 3,023’ 6.151” 8.340” Seal Stem
3 ~1,500’ 3.958” 4.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface (75% excess) 1022 sx
4-1/2” TOC @ TOL (40% Excess) PLANNED
8-1/2”
OH TOF @ 7358’: 143’ Fish (BHA)
8-1/2”
hole
2
3
Production Packer run at +/-2940' MD per S. McLaughlin email attached.
Updated by DMA 08-24-23
PROPOSED
Lewis River Unit
LRU C-02
PTD: 223-057
API: 50-283-20190-00-00
PBTD= ±7,257’ MD / TVD = ±6,822’
TD = 7,501 MD / TVD = ±7,070’
RKB to GL = 18.5’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8" Surf Csg 47 L-80 TXP 8.681” Surf 3,186’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,999’ 7,337’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 3,023’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 3,023’ 6.151” 8.540” Liner hanger / LTP Assembly
2 3,023’ 6.151” 8.340” Seal Stem
3 ~1,500’ 3.958” 4.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface (75% excess) 1022 sx
4-1/2” TOC @ TOL (40% Excess) PLANNED
8-1/2”
OH TOF @ 7358’: 143’ Fish (BHA)
8-1/2”
hole
2
3
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Bel I10-Ty 13 ±4,836’ 6,820’ ±4,435’ ±6,392’ ±984' Proposed TBD
Bel I10-Ty 13
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.
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From:McLellan, Bryan J (OGC)
To:Sean McLaughlin
Subject:RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Date:Thursday, August 31, 2023 4:46:00 PM
Sean,
Hilcorp has authorization to reduce the IA test pressure to 3000 psi based on the lower MPSP.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 4:43 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Bryan,
I’ve learned that the 9-5/8’ x 4-1/2” packer going in hole on LRU-C2 on is a shear to release packer
and a 3500 psi may be pushing the force envelop. The vendor is looking into in.
I’d like to request to reduce the IA test pressure from 3500 psi to 3000 psi. The justification is that
we did not drill to our planned TD and have a lower then planned MASP.
Shoe depth – 7341’ MD and 6909’ TVD
Bottom perforation – 6850’ MD
10 PPG formation
BHP=3593 psi (shoe)
MASP = 2902 psi
Regards,
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 31, 2023 11:09 AM
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Sean,
Hilcorp has authorization to proceed with the planned changes.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:34 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: RE: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
The top of the PBR is a 3001’. We will have a WLEG, X nip, and full joint below the packer. Packer
depth will be around 2940’.
sean
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, August 31, 2023 10:16 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] RE: LRU-C2 (223-057) Upper completion change
Sean,
Thanks for the notification. What’s the approximate planned depth for the production packer?
Regards
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.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Thursday, August 31, 2023 10:01 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Cody Dinger <cdinger@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com>
Subject: LRU-C2 (223-057) Upper completion change
Bryan,
After running the tie-back on LRU-C2 the IA and tubing failed to test. Both slickline and eline ran leak
detection logs and the leak point was not conclusively identified. The completion was pulled and
rerun with replacement equipment. The tubing now leaks while the IA holds solid indicating a
potential problem with the PBR. We will swap the seal stem for a production packer. There are no
changes to the planned test pressures.
Regards,
sean
Sean McLaughlin
Hilcorp Alaska, LLC
Drilling Engineer
Sean.McLaughlin@hilcorp.com
Cell: 907-223-6784
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this 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.
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.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Lewis River Field, Lewis River Undefined Gas Pool, LRU C-02
Hilcorp Alaska, LLC
Permit to Drill Number: 223-057
Surface Location: 32’ FEL, 970’ FSL, Sec 34, T15N, R9W, SM, AK
Bottomhole Location: 506' FSL, 2174' FWL, Sec 35, T15N, 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,
Jessie Chmielowski
Commissioner
DATED this ___ day of July 2023. 20
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.07.20 15:37:14 -08'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 8,459' TVD: 8,008'
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): 121.9 15. Distance to Nearest Well Open
Surface: x-350275 y- 2683741 Zone-4 103.4 to Same Pool: 1649' to LRU C1RD
16. Deviated wells:Kickoff depth: 319 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 36 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
12-1/4" 9-5/8" 47# L-80 TXP 3,223' Surface Surface 3,223' 2,866'
8-1/2" 4-1/2" 12.6# L-80 JFE LION 5,436' 3,023' 2,682' 8,459' 8,008'
Tieback 4-1/2" 12.6# L-80 JFE LION 3,023' Surface Surface 3,023' 2,682'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
7/20/2023
1786' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
907-777-8413
Tieback Assy.
Drilling Manager
Monty Myers
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
Production
Liner
Intermediate
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 1713 ft3 / T - 346 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
1280
18. Casing Program:Top - Setting Depth - BottomSpecifications
4164
GL / BF Elevation above MSL (ft):
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 2001 ft3 / 205 ft3
3363
672’ FSL, 1251’ FWL, Sec 35, T15N, R9W, SM, AK
506' FSL, 2174' FWL, Sec 35, T15N, R9W, SM, AK
LOCI 89-28
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
32’ FEL, 970’ FSL, Sec 34, T15N, R9W, SM, AK ADL 58798
LRU C-02
Lewis River Unit
Lewis River Undefined Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
s
D
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
6.27.2023
By Grace Christianson at 3:46 pm, Jun 27, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.06.27 15:25:08 -08'00'
Monty M
Myers
MDG 7/20/2023
BJM 7/16/23
DSR-6/28/23
50-283-20190-00-00223-057
BOP test to 3500 psi, annular test to 2500 psi.
7" drilling liner will be required if extensive lost circulation zone is encountered.
Submit LOT/FIT results within 24 hrs of performing test.
GCW 07/20/2023
07/20/23
07/20/23
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2023.07.20 15:37:34 -08'00'
LRU C-02
Drilling Program
Beluga River Unit
Rev 0
June 22, 2023
LRU C-02
Drilling Procedure
Contents
1.0 Well Summary...........................................................................................................................2
2.0 Management of Change Information........................................................................................3
3.0 Tubular Program:......................................................................................................................4
4.0 Drill Pipe Information:..............................................................................................................4
5.0 Internal Reporting Requirements.............................................................................................5
6.0 Planned Wellbore Schematic.....................................................................................................6
7.0 Drilling / Completion Summary................................................................................................7
8.0 Mandatory Regulatory Compliance / Notifications..................................................................8
9.0 R/U and Preparatory Work.....................................................................................................10
10.0 N/U 21-1/4” Conductor ............................................................................................................11
11.0 Drill 12-1/4” Hole Section ........................................................................................................13
12.0 Run 9-5/8” Surface Casing ......................................................................................................15
13.0 Cement 9-5/8” Surface Casing.................................................................................................18
14.0 BOP N/U and Test....................................................................................................................21
15.0 Drill 8-1/2” Hole Section ..........................................................................................................22
16.0 Run 4-1/2” Production Liner ...................................................................................................25
17.0 Cement 4-1/2” Production Liner .............................................................................................28
18.0 4-1/2” Liner Tieback Polish Run .............................................................................................31
19.0 4-1/2” Tieback Run ..................................................................................................................32
20.0 Diverter Schematic ..................................................................................................................33
21.0 BOP Schematic ........................................................................................................................34
22.0 Wellhead Schematic.................................................................................................................35
23.0 Days Vs Depth..........................................................................................................................36
24.0 Geo-Prog..................................................................................................................................37
25.0 Anticipated Drilling Hazards ..................................................................................................38
26.0 Hilcorp Rig 147 Layout ...........................................................................................................40
27.0 FIT/LOT Procedure.................................................................................................................41
28.0 Choke Manifold Schematic......................................................................................................42
29.0 Casing Design Information......................................................................................................43
30.0 8-1/2” Hole Section MASP .......................................................................................................44
31.0 Spider Plot w/ 660’ Radius for SSSV.......................................................................................45
32.0 Surface Plat (As-Built NAD27)................................................................................................46
Page 2 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
1.0 Well Summary
Well LRU C-02
Pad & Old Well Designation LRU C-Pad / grassroots well
Planned Completion Type 4-1/2” Cemented Production Liner
Target Reservoir(s)Beluga/Tyonek Gas Sands
Planned Well TD, MD / TVD 8,459’ MD / 8,008’ TVD
PBTD, MD / TVD 8,379’ MD / 7,929’ TVD
Surface Location (Governmental)32’ FEL, 970’ FSL, Sec 34, T15N, R9W, SM, AK
Surface Location (NAD 27)X=350275.29 Y=2683741.17
Top of Productive Horizon
(Governmental)672’ FSL, 1251’ FWL, Sec 35, T15N, R9W, SM, AK
TPH Location (NAD 27)X=351555.00, Y=2683426.45
BHL (Governmental)506’ FSL, 2174’ FWL, Sec 35, T15N, R9W, SM, AK
BHL (NAD 27)X=325475.36, Y=2683245.51
AFE Number
AFE Drilling Days 28 DRLG
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)3363 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)4164 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 121.9’ (103.4 + 18.5)
Ground Elevation 103.4’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
2.0 Management of Change Information
Page 4 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 -
Surface
12-1/4”9-5/8”8.681”8.525”10.625”47 L-80 TXP 6870 4760 1086
Prod
8-1/2”4-1/2”3.958”3.833”5.002”12.6 L-80 JFELION 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
Page 5 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area –this will not save the data entered, and will navigate to another data entry
tab.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a
username to login with.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
Page 6 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
6.0 Planned Wellbore Schematic
Page 7 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
7.0 Drilling / Completion Summary
LRU C-02 is a grassroots development well to be drilled from Lewis River C-Pad. This well will be
targeting the Beluga and Tyonek sands identified for gas production. The base plan is a directional wellbore
with a kickoff point at ~300’ MD. Maximum hole angle will be ~36 deg before dropping to 10 deg and TD
of the well will be 8,459’ TMD/ 8,008’ TVD.
Drilling operations are expected to commence approximately July 20, 2023. The Hilcorp Rig # 147 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to ~3,223’ MD / 2,866’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example) will be run to determine
TOC. Necessary remedial action will then be discussed with AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 147 to well site
2. N/U Diverter
3. Drill 12-1/4” hole to 3,223’ MD.
4. Run and cement 9-5/8” surface casing.
5. ND conductor riser, N/U & test 11” x 5M BOP.
6. Drill Out shoe and perform FIT.
7. Drill 8-1/2” hole section to 8,459’ MD. Perform wiper trips as needed.
8. POOH w/drillpipe.
9. Run and cmt 4-1/2” production liner.
10. Polish PBR
11. RIH and land 4-1/2” tieback string in liner top.
12. MIT-T, MIT-IA
13. N/D BOP, N/U tree, RDMO.
Reservoir Evaluation Plan:
Surface hole: Gr/Res MWD
Production Hole: Triple Combo MWD, LWD Pressures, e-line sonic and image logs
x LWD Pressures and E-line logs dependent on hole conditions
Mud loggers from surface casing point to TD.
gp
e Beluga and Tyonek sands i
gp
Mud loggers from surface casing point to TD.
Page 8 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling of LRU C-02. Ensure to provide
AOGCC at least 24 hrs notice prior to testing BOPs.
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 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the PTD.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14-day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
Regulation Variance Requests:
Page 9 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 21-1/4” x 2M diverter Function Test Only
8-1/2”
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 48 hours notice prior to testing Diverter and BOPs.
x 48 hours notice prior to casing running & cement operations.
x 48 hours notice prior to performing MITIA.
x Any other notifications required in PTD.
Additional requirements may be stipulated on PTD and Sundry.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 16” conductor and cellar installed and surveyed.
9.2 Install slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with
flowline later.
9.3 Level pad and ensure enough room for layout of rig footprint and R/U.
9.4 Layout Herculite on pad to extend beyond footprint of rig.
9.5 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.6 RU Mud loggers on surface hole section for gas detection only. No samples required
9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.8 Mix mud for 12-1/4” hole section.
9.9 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” Conductor
10.1 N/U 21-1/4” Diverter
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure. Ensure to notify AOGCC inspector to witness
function test of diverter.
x NOTE: Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
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10.5 Rig 147 Orientation:
Note: Actual layout may be different on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 12-1/4” hole section to 3,223’ MD/ 2,866’ 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 past 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’-1000’ 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 and overbalance.
x Take MWD surveys every stand drilled (60’ intervals).
11.5 12-1/4” 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. Ensure mud weight is at 10.0 ppg prior to 2,800’
MD.
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 –10.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
80-3223’ 9.0 – 10.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
Reservoir pressure ramps up from 8.5 ppg to 10 ppg just below the planned surface casing setting point. -bjm
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System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.6 At TD;pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8”casing running equipment.
x Ensure 9-5/8”TXP x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint. Visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 9-5/8”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 Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
9-5/8” 47# TXP M/U torques
Casing OD Minimum Maximum Yield Torque
9-5/8”21,440 ft-lbs 26,200 ft-lbs 54,100 ft-lbs
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer volume.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 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:
16” Conductor x 9-5/8”
casing annulus:
80’ x .12887 bpf =10.31 57.9
12.0 ppg LEAD:
12-1/4” OH x 9-5/8”
Casing annulus:
(2723’ –80’) x .05578 bpf x
2.00 =
294.86 1655.5
Total LEAD:305.17 bbl 1713.4 ft3
15.4 ppg TAIL:
12-1/4” OH x 9-5/8”
Casing annulus:
(3223’- 2723’) x .05578 bpf x
2.00 =
55.78 313.2
15.4 ppg TAIL:
9-5/8” Shoe track:
80 x .07321 bpf =5.86 32.9
Total TAIL:61.64 bbl 346.1 ft3
TOTAL CEMENT VOL:366.81 bbl 2059.5 ft3
Calculations verified assuming 100% excess open hole volume, not 50% as mentioned above.
-bjm
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Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Displacement calculation:
3223’-80’ = 3143’ x .07321 bpf = 231 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 5.9 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a cement evaluation log between 12 –18 hours after CIP.
x Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes
is 1.5”.
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.15 R/D cement equipment. Flush out wellhead with FW.
13.16 Back out and L/D landing joint. Flush out wellhead with FW.
Lead Slurry (2723’ MD to surface)Tail Slurry (3223’ to 2723’ MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.44 ft3/sk 1.16 ft3/sk
Mixed Water 14.40 gal/sk 5.03 gal/sk
Mixed Fluid 14.40 gal/sk 5.03 gal/sk
verified displacement -bjm
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13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.18 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 ND conductor riser.
14.2 N/U wellhead assy. Test to 5000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Run 4-1/2” BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Utilize 4-1/2” test joint to cover drilling and 4-1/2” liner.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 10.0 ppg 6% KCL PHPA mud system. If MW at surface TD was greater than 10.0 ppg,
increase density of new mud to match.
14.8 R/U mud loggers for production hole section.
14.9 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 8-1/2” Hole Section
15.1 Pull test plug, run and set wear bushing.
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH, conduct shallow hole test of MWD, and confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 8-1/2” hole section mud program summary:
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 10.00 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
3,227’-8,459’10.0 –11.0 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 10.0 –11.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 8-1/2” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on
FIT/LOT graph. AOGCC requirement is 50% of burst. 9-5/8” burst is 6870 psi / 2 = 3435 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT. Target value 13.2 ppg EMW.
Note: Offset field test data predicts frac gradient at the 9-5/8” shoe to be between 11.5 –21.0
ppg EMW. A 13.2 ppg FIT results in a >15 bbl kick tolerance while drilling with the planned
MW of 11.0 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
15.14 Drill 8-1/2” hole section to 8,459’ MD / 8,008’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 300 - 550 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 5,800’ MD), trip back to the 9-5/8” 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 Collect samples every 30’.
x The Tyonek T6 (prognosed @ ~6,022MD) is expected to be depleted and poses a lost
circulation risk. Ensure fluid volume is sufficient to keep up with any losses encountered.
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15.15 At TD; pump sweeps, CBU, and perform pressure sampling per geologist.
15.16 After final pressure sample, perform wiper trip back to the 9-5/8” shoe.
15.17 RIH t/TD, CBU, and TOH with the drilling assy, standing back drill pipe.
15.18 POOH and LD BHA.
15.19 RU E-Line and perform wireline logging plan.
15.20 RD E-Line. PU 8-1/2” clean out BHA, and TIH to TD.
15.21 Pump sweep, CBU and condition mud for casing run.
15.22 POOH and LD BHA.
15.23 2-7/8” x 5-1/2” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
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16.0 Run 4-1/2” Production Liner
16.1. R/U 4-1/2”casing running equipment.
x Ensure 4-1/2”JFELION x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill liner while running.
x Ensure all liner has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U liner tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint, FC joint, and landing collar joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 4-1/2” production liner
x Fill liner 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 9-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 4-1/2” production liner
4-1/2” 12.6# JFELION M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”6,030 ft-lbs 6,690 ft-lbs 7,360 ft-lbs
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16.6. Run in hole w/ 4-1/2” liner to the 9-5/8” casing shoe.
16.7. Fill the liner with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight, and torque of the liner.
16.9. Circulate 2X bottoms up at shoe, ease liner thru shoe.
16.10. Continue to RIH w/ liner no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set liner slowly in and out of slips.
16.12. PU 4-1/2”X 9-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight, and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Monitor PUW & SOW. Circulate BU if needed. Highlight zones of interest before running past,
ex: coals
16.15. Swedge up and wash last stand to bottom. P/U 2-5’ off bottom. Note slack-off and pick-up
weights.
16.16. 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 (whichever is longer). Reduce the low-end rheology of the drilling fluid by
adding water and thinners.
16.17. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
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17.0 Cement 4-1/2” Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
9-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .05354 bpf =10.71 60.1
12.0 ppg LEAD:
9-5/8” csg x 4-1/2” liner
annulus:
200’ x .05354 bpf =10.71 60.1
12.0 ppg LEAD:
8-1/2” OH x 4-1/2” annulus:
(7959’ –3223’) x .05051 bpf x
1.4 =
334.93 1880.5
Total LEAD:356.35 bbl 2000.7 ft3
15.4 ppg TAIL:
8-1/2” OH x 4-1/2” annulus:
(8459’- 7959’) x .05051 bpf x
1.4 =
35.36 198.5
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf =1.22 6.8
Total TAIL:36.58 205.3 ft3
TOTAL CEMENT VOL:392.93 bbl 2206.0 ft3
Verified Cement Calcs. -bjm
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Cement Slurry Design:
17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow –continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than ½ shoe track. Shoe track volume is 1.2 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight.
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
Lead Slurry (7959’ MD to 3023’ MD)Tail Slurry (8459’ to 7959’ 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
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pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
Backup release from liner hanger:
17.21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will
have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure
and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear
screws.
17.22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then
proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop
1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up
with workstring to release collet from the profile.
17.24. WOC minimum of 12 hours before testing liner to 3500 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 liner 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” liner tally & liner and cement report to cdinger@hilcorp.com and
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 4-1/2” Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, LDDP and polish mill.
NOTE: if a cleanout run is needed to clean out the liner, BOP’s need to be tested with 2-7/8” test
joint prior to picking up workstring.
18.4. Test casing and liner lap to 3,500 psi / 30 min. Ensure to chart record casing test.
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19.0 4-1/2” Tieback Run
19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 DWC/C-HT tubing.
x Install Chemical injection mandrel at ~500’. Detail to be communicated by OE.
o Control line spooler needed
4-1/2” 12.6# JFELION M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”6,030 ft-lbs 6,690 ft-lbs 7,360 ft-lbs
19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
19.3 Circulate inhibited completion fluid.
19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 4-1/2” liner and tieback to 3,500 psi / 30 min and chart for 30 minutes.48hr AOGCC
notice required.
19.7 Test 9-5/8” x 4-1/2” annulus to 3,500 psi / 30 min and chart for 30 minutes. 48hr AOGCC
notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO
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20.0 Diverter Schematic
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21.0 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Geo-Prog
See attached updated table including shallower zones. -bjm
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25.0 Anticipated Drilling Hazards
12-1/4”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 ensure 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.
Pressure ramps up from normal to 10 ppg starting at 3185 ft TVD in the Beluga G. -bjm
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8-1/2” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in Beluga River in 2020, ensure all LCM inventory is fully
stocked before drilling out surface casing. While severe lost circulation has not been encountered in
LRU, The Tyonek T6 is depleted since the last well drilled and can be a lost circulation risk.
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.
10 ppg EMW is anticipated throughout this hole section, based on table on page 44 of the drilling program. -bjm
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26.0 Hilcorp Rig 147 Layout
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27.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
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28.0 Choke Manifold Schematic
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29.0 Casing Design Information
12-1/4"Mud Density:10.0 ppg
8-1/2"Mud Density:11.0 ppg
Mud Density:
3363 psi (see attached MASP determination & calculation)
3363 psi (see attached MASP determination & calculation)
Collapse Calculation:
Section Calculation
1 Normal gradient external stress (0.45 psi/ft) and the casing evacuated for the internal stress
1234
9-5/8" 4-1/2"
00
00
3,223 8,459
2,866 8,008
3,223 8,459
47 12.6
L-80 L-80
TXP JFE LION
151,481 106,583
258,064 106,583
1086 288
4.21 2.70
1,290 3,604
4,750 7,500
3.68 2.08
965 3,363
6,870 8,430
7.12 2.51Worst case safety factor (Burst)
DATE: 05/31/2023
WELL: LRU C-02
FIELD: Lewis River
DESIGN BY: Frank Roach
Hole Size
Hole Size
Hole Size
MASP:
Production Mode
Casing Section
MASP:
Drilling Mode
MASP:
Length
Top (TVD)
Minimum Yield (psi)
Weight (ppf)
Grade
Connection
Weight w/o Bouyancy Factor (lbs)
Min strength Tension (1000 lbs)
Collapse Resistance w/o tension (Psi)
Worst Case Safety Factor (Collapse)
MASP (psi)
Worst Case Safety Factor (Tension)
Collapse Pressure at bottom (Psi)
Calculation & Casing Design Factors
Calculation/Specification
Casing OD
Bottom (MD)
Bottom (TVD)
Top (MD)
Tension at Top of Section (lbs)
Design Criteria:
Page 44 Version 0 June, 2023
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30.0 8-1/2” Hole Section MASP
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31.0 Spider Plot w/ 660’ Radius for SSSV
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32.0 Surface Plat (As-Built NAD27)
! "
#$ %
#
#
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500
8000True Vertical Depth (1000 usft/in)0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000
Vertical Section at 102.00° (1000 usft/in)
LRU C-02 wp05 Tgt1
9 5/8" x 12-1/4"
4 1/2" x 8-1/2"
5 00
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
8 0 0 0
8 4 5 9 LRU C-02 wp05
Start Dir 3º/100' : 318.5' MD, 318.5'TVD
End Dir : 1525.95' MD, 1447.11' TVD
Start Dir 2º/100' : 2484.15' MD, 2220.1'TVD
End Dir : 3796.35' MD, 3416.51' TVD
Total Depth : 8458.57' MD, 8007.9' TVD
STERLING_B
BELUGA_D
BELUGA_G
BELUGA_H11
BELUGA_I9
BRU_TYONEK
Tyonek T6 / L
T10
T17
T20
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: Lewis River C-02
103.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2683741.17 350275.29 61° 20' 34.0886 N 150° 51' 9.7496 W
SURVEY PROGRAM
Date: 2023-05-31T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 3224.00 LRU C-02 wp05 (LRU C-02) 3_MWD+AX+Sag
3224.00 8458.57 LRU C-02 wp05 (LRU C-02) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
2514.90 2393.00 2834.76 STERLING_B
2636.90 2515.00 2972.74 BELUGA_D
3178.90 3057.00 3552.96 BELUGA_G
3678.90 3557.00 4062.78 BELUGA_H11
4332.90 4211.00 4726.87 BELUGA_I9
5119.90 4998.00 5526.01 BRU_TYONEK
5607.90 5486.00 6021.54 Tyonek T6 / L
5892.90 5771.00 6310.94 T10
6985.90 6864.00 7420.80 T17
7575.90 7454.00 8019.90 T20
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Lewis River C-02, True North
Vertical (TVD) Reference:RKB As-Built MSL @ 121.90usft (HEC 147)
Measured Depth Reference:RKB As-Built MSL @ 121.90usft (HEC 147)
Calculation Method:Minimum Curvature
Project:Beluga River North
Site:Lewis River
Well:Lewis River C-02
Wellbore:LRU C-02
Design:LRU C-02 wp05
CASING DETAILS
TVD TVDSS MD Size Name
2865.90 2744.00 3223.39 9-5/8 9 5/8" x 12-1/4"
8007.90 7886.00 8458.57 4-1/2 4 1/2" x 8-1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00
2 318.50 0.00 0.00 318.50 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 318.5' MD, 318.5'TVD
3 1525.95 36.22 103.18 1447.11 -84.15 359.42 3.00 103.18 369.06 End Dir : 1525.95' MD, 1447.11' TVD
4 2484.15 36.22 103.18 2220.10 -213.23 910.75 0.00 0.00 935.18 Start Dir 2º/100' : 2484.15' MD, 2220.1'TVD
5 3796.35 10.00 100.00 3416.51 -323.34 1409.20 2.00 -178.75 1445.63 End Dir : 3796.35' MD, 3416.51' TVD
6 5796.35 10.00 100.00 5386.13 -383.64 1751.22 0.00 0.00 1792.72 LRU C-02 wp05 Tgt1
7 8458.57 10.00 100.00 8007.90 -463.92 2206.49 0.00 0.00 2254.72 Total Depth : 8458.57' MD, 8007.9' TVD
-900
-750
-600
-450
-300
-150
0
150
300
450
600
750
900
1050
1200
South(-)/North(+) (300 usft/in)-150 0 150 300 450 600 750 900 1050 1200 1350 1500 1650 1800 1950 2100 2250 2400 2550
West(-)/East(+) (300 usft/in)
LRU C-02 wp05 Tgt1
9 5/8" x 12-1/4"
4 1/2" x 8-1/2"
250500 750100012501500175020002250250027503000325035003750400042504500475050005250550057506000625065006750700072507500775080008008LRU C-02 wp05Start Dir 3º/100' : 318.5' MD, 318.5'TVD
End Dir : 1525.95' MD, 1447.11' TVD
Start Dir 2º/100' : 2484.15' MD, 2220.1'TVD
End Dir : 3796.35' MD, 3416.51' TVD
Total Depth : 8458.57' MD, 8007.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
2865.90 2744.00 3223.39 9-5/8 9 5/8" x 12-1/4"
8007.90 7886.00 8458.57 4-1/2 4 1/2" x 8-1/2"
Project: Beluga River North
Site: Lewis River
Well: Lewis River C-02
Wellbore: LRU C-02
Plan: LRU C-02 wp05
WELL DETAILS: Lewis River C-02
103.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2683741.17 350275.29 61° 20' 34.0886 N 150° 51' 9.7496 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Lewis River C-02, True North
Vertical (TVD) Reference: RKB As-Built MSL @ 121.90usft (HEC 147)
Measured Depth Reference:RKB As-Built MSL @ 121.90usft (HEC 147)
Calculation Method:Minimum Curvature
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4.00
Separation Factor0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550
Measured Depth (900 usft/in)
Lewis River C-01RD
Lewis River C-01
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
NOERRORS
WELL DETAILS:Lewis River C-02 NAD 1927 (NADCON CONUS)Alaska Zone 04
103.40
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2683741.17 350275.29 61° 20' 34.0886 N 150° 51' 9.7496 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Lewis River C-02, True North
Vertical (TVD) Reference:RKB As-Built MSL @ 121.90usft (HEC 147)
Measured Depth Reference:RKB As-Built MSL @ 121.90usft (HEC 147)
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-05-31T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 3224.00 LRU C-02 wp05 (LRU C-02) 3_MWD+AX+Sag
3224.00 8458.57 LRU C-02 wp05 (LRU C-02) 3_MWD+AX+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
Centre to Centre Separation (60.00 usft/in)0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550
Measured Depth (900 usft/in)
Lewis River C-01RD
Lewis River C-01
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
18.50 To 8458.57
Project: Beluga River North
Site: Lewis River
Well: Lewis River C-02
Wellbore: LRU C-02
Plan: LRU C-02 wp05
CASING DETAILS
TVD TVDSS MD Size Name
2865.90 2744.00 3223.39 9-5/8 9 5/8" x 12-1/4"
8007.90 7886.00 8458.57 4-1/2 4 1/2" x 8-1/2"
Page 44 Version 0 June, 2023
LRU C-02
Drilling Procedure
Rev 0
30.0 8-1/2” Hole Section MASP
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:Frank Roach
To:McLellan, Bryan J (OGC)
Cc:Roby, David S (OGC); Guhl, Meredith D (OGC); Roby, David S (OGC)
Subject:RE: [EXTERNAL] LRU C-02 PTD surface hole pressures/shallow hazards
Date:Thursday, June 29, 2023 4:59:33 PM
Attachments:LRU C-02 Drilling Program MASP Page.pdf
Bryan,
Attached is the edited table for page 44. The edit has the shallow zones above the surface casing
depth, including the potential shallow gas hazard in the Sterling B.
Let me know if you need anything additional.
Regards,
Frank V Roach
Drilling Engineer
Hilcorp Alaska, LLC
907.854.2321 mobile
907.777.8413 office
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, June 29, 2023 13:59
To: Frank Roach <Frank.Roach@hilcorp.com>
Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Guhl, Meredith D (OGC)
<meredith.guhl@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>
Subject: [EXTERNAL] LRU C-02 PTD surface hole pressures/shallow hazards
Frank,
The table on page 44 of the drilling procedure lists pressures from 3185’ TVD and deeper, starting at
10 ppg EMW. Can you list the shallower zones and pressures to show where the pressure ramps up
from normal hydrostatic pressure to 10 ppg, also include any known shallow hazards/gas
accumulations that will be drilled with surface hole?
Thank you
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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From:Frank Roach
To:Guhl, Meredith D (OGC); McLellan, Bryan J (OGC)
Cc:Roby, David S (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] LRU-C-02 (PTD 223-057) - Questions regarding H2S
Date:Thursday, July 20, 2023 7:20:58 AM
You don't often get email from frank.roach@hilcorp.com. Learn why this is important
Meredith,
H2S is not expected in reservoir and no H2S has been previously measured.
Rig 147 does have H2S sensors and alarms.
Regards,
Frank V Roach
Drilling Engineer
Hilcorp Alaska, LLC
907.854.2321 mobile
907.777.8413 office
From: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Sent: Wednesday, July 19, 2023 15:27
To: Frank Roach <Frank.Roach@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] LRU-C-02 (PTD 223-057) - Questions regarding H2S
Hello Frank,
I’m finishing the review of LRU C-02, and am writing to inquire if there is any H2S in the reservoir,
either expected or previously measured? The last permit reviewed was in 2001, so there isn’t a lot of
current data available for this unit.
Does Hilcorp Rig 147 have H2S sensors and alarms?
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-057
Undefined Gas Pool
X
LRU C-02
X
Lewis River Unit
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:LEWIS RIVER UNIT C-02Initial Class/TypeDEV / 1-GASGeoArea820Unit11220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230570LEWIS RIVER, UNDEFINED GAS - 500500NA1 Permit fee attachedYes Entire Well lies within ADL0058798.2 Lease number appropriateYes3 Unique well name and numberYes LEWIS RIVER, UNDEFINED GAS - 500500 - governed by Statewide Regs4 Well located in a defined poolYes Well is located 1786' from unit boundary.5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3363. BOP rated to 5000 psi (BOP test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not expected in reservoir. Hilcorp Rig 147 has H2S sensors and alarms. See email 7/20/202335 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.405 to 0.521 psi/ft (7.8 to 10 ppg EMW). Operators mud program appears sufficient36 Data presented on potential overpressure zonesNA LCM and CaCO3 onsite availble to mitigate losses and weight up as needed. Tyonek T6 is noted as depleted37 Seismic analysis of shallow gas zonesNA and can be a lost circulation risk, p. 41. Coals are also present.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprMDGDate7/19/2023ApprBJMDate7/17/2023ApprMDGDate7/20/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 7/20/2023
