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Alaska Oil and Gas Conservation Commission
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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: Install Cap String
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 10,012 feet N/A feet
true vertical 8,892 feet N/A feet
Effective Depth measured 9,449 feet N/A feet
true vertical 8,338 feet N/A 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 4,062' MD 3,223' TVD
Packers and SSSV (type, measured and true vertical depth) N/A N/A 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:
Scott Warner, Operations Engineer
324-197
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
2039
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
scott.warner@hilcorp.com
907-564-4506
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
175
Size
120'
38 1741888
0 9235
91
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-014
50-133-20710-00-00
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:
Private
Ninilchik / Beluga-Tyonek Gas
Ninilchik Unit Paxton 12
Plugs
Junk measured
Length
Production
Liner
5,957'
Casing
Structural
8,891'10,011'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
4,292'
7,500psi
2,980psi
6,890psi
8,430psi
4,292' 3,392'
Burst Collapse
1,410psi
4,790psi
p
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6. A
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Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 7:46 am, Jul 29, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.07.26 16:09:22 -
08'00'
Noel Nocas
(4361)
Page 1/1
Well Name: NINU Paxton 12
Report Printed: 7/24/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:11/10/2023 End Date:
Report Number
2
Report Start Date
7/15/2024
Report End Date
7/16/2024
Operation
Continue filling reel with foamer from previous night.
Rig Up Cap string truck. Stab 3/8" SS tubing into injector head and pack off assembly. Nipple up injector head. Install DCIV-8860 foot valve with opening
pressure of 2450 psi. Stab on well. Pressure test pack off assembly and wellhead adapter/bowen connection to 250/3500 psi.
RIH with Capillary tubing to 8100'. Set at depth in tension 2250 lbs free jamgomg weight. Apply 3000 psi to dynamic pack off and close in. Set static pack offs
and install hanger assembly. Rig back injector head.
Remove cap string spool from craddle and set along side wellhead. Rig down truck. Turn well over to production.
API: 50-133-20710-00-00 Field: Ninilchik
Sundry #:
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-014
Updated by DMA 07-24-24
SCHEMATIC
Ninilchik Unit
Paxton 12
API: 50-133-20710-00-00
PTD: 223-014
PBTD = 9,454 / TVD = 8,341
TD = 10,012 / TVD = 8,892
RKB to GL = 18
Cactus EN-2CCL 11 Hgr, 4.5 EUE lift threads
4 type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T81 8,039 8,051 6,958 6,970 12 11/20/23 Open
T120 8,625 8,645 7,531 7,550 20 6/07/23 &
6/28/23 Open
T120 8,645 8,665 7,550 7,569 20 6/28/23 Open
T140 8,694 8,714 7,599 7,618 20 8/15/23 Isolated
T145 8,930 8,945 7,830 7,845 15 5/19/23 Open
T146 8,980 9,070 7,879 7,968 90 8/20/23 Open
T160 9,484 9,504 8,373 8,392 20 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16 Conductor Driven
to Set Depth 84 X-56 Weld 15.01 Surf 120
7-5/8" Surf Csg 29.7 L-80 CDC 6.875 Surf 4,292
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958 4,054 10,011
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958 Surf 4,062
T120
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 156 3.813 5.500 SSSV: ONYX-R5E
2 1,515 3.870 4.500 Chemical Injection Sub
3 4,054 4.875 6.540 Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930-
8945 3.375 Owen 4.5 X-Span Patch set 8/14/23
4 9,449 CIBP, milled and pushed to 9,454 CTM
6-3/4
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
T81
Capillary String 3/8 Installed 7/15/24
Top Bottom
MD 0 8,100
TVD 0 7,017
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Cap String
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number):10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
10,012'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
Scott Warner, Operations Engineer
scott.warner@hilcorp.com
907-564-4506
Noel Nocas, Operations Manager 907-564-5278
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
12.6# / L-80 4,062'
May 29, 2024
N/A; N/A N/A; N/A
See Schematic See Schematic Tieback 4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Private
223-014
50-133-20710-00-00
Ninilchik Beluga-Tyonek Gas Same
CO 701F
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Paxton 12
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
8,892'9,449'8,338'~2853psi N/A
MD
2,980psi
6,890psi
120'
3,392'
120'
4,292'
Perforation Depth MD (ft):
5,957'4-1/2"
16"
7-5/8"
120'
4,292'
8,430psi8,891'10,011'
m
n
P
s
t
66
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Noel Nocas
(4361)
Digitally signed by Noel Nocas
(4361)
Date: 2024.05.17 10:04:45
-08'00'
324-297
By Grace Christianson at 10:51 am, May 17, 2024
Obsolete form SFD
SFD 5/17/2024 DSR-5/20/24BJM 5/23/24
10-404
This is an outdated 10-403 form. Use the current 10-403 found on AOGCC for future sundry applications.
*&:JLC 5/23/2024
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.05.24 12:02:31
-08'00'05/24/24
RBDMS JSB 052824
Well Prognosis
Well: Paxton 12
Date: 5/15/24
Well Name: Paxton 12 API Number: 50-133-20710-00-00
Current Status: Producing Gas Well Permit to Drill Number: 223-014
Regulatory Contact: Donna Ambruz (907) 777-8305
First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C)
Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C)
Maximum Expected BHP: 3692 psi @ 8392’ TVD Based on 0.44 psi/ft
Max. Potential Surface Pressure: 2853 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: 0.67 psi/ft using 12.8 ppg EMW FIT the surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.67-0.1) = 2853 psi / 0.57 = 5005‘ TVD
Top of Applicable Gas Pool: 1570’ MD/ 1501’ TVD
Well Status: Online Gas Producer flowing at 2450 mcfd, 50 bwpd, 95 psi FTP
Brief Well Summary
Paxton 12 is a 2023 new drill that tested multiple Tyonek zones before being completed as a producer in the
Tyonek 120 & 140 sands. The 140 was later patched, the T-146 perforated, followed by the T81 three months
later. Gas rates have declined and the well is relying on soap drops every 3-4 hrs to stay unloaded.
The purpose of this sundry is to install a cap string for soap injection to optimize well performance. This will
require the SSSV to be blocked open at surface while the cap string is installed.
Notes Regarding Wellbore Condition
x Inclination
o Max deviation of 50.9° @ 2146’ MD
o Max DLS of 4.71°/100’ @ 1155’ MD
x Recent Tags/Min ID
o 11/20/23: Perforated T81 w/ 2-3/4” guns from 8039-8051’ MD
o 9/7/23: 2.25” x 4’ DD bailer to 9398’ KB- Empty bailer
o 8/15/23: Patch set @ 8691’ MD-8717’ MD w/ 3.375” ID
Procedure:
1. RU Cap String Truck
2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and
pressure test against swab valve to 3000 psi
3. RIH with 3/8” capillary string to ±8100’ MD
a. Set cap string as deep as practical in fluid
4. Install slips and connect tubing to chemical injection pump
5. Set spool of remaining line near well
6. RD cap string Unit, and turn well over to production
Attachments:
1. Current Schematic
2. Proposed Schematic
Updated by DMA 05-10-24
SCHEMATIC
Ninilchik Unit
Paxton 12
API: 50-133-20710-00-00
PTD: 223-014
PBTD = 9,454’ / TVD = 8,341’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
Cactus EN-2CCL 11” Hgr, 4.5” EUE lift threads
4” type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T81 8,039’ 8,051’ 6,958’ 6,970’ 12’ 11/20/23 Open
T120 8,625’ 8,645’ 7,531’ 7,550’ 20’ 6/07/23 &
6/28/23 Open
T120 8,645’ 8,665’ 7,550’ 7,569’ 20’ 6/28/23 Open
T140 8,694’ 8,714’ 7,599’ 7,618’ 20’ 8/15/23 Isolated
T145 8,930’ 8,945’ 7,830’ 7,845’ 15’ 5/19/23 Open
T146 8,980’ 9,070’ 7,879’ 7,968’ 90’ 8/20/23 Open
T160 9,484’ 9,504’ 8,373’ 8,392’ 20’ 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 4,054’ 10,011’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 4,062’
T120
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 156’ 3.813” 5.500” SSSV: ONYX-R5E
2 1,515’ 3.870” 4.500” Chemical Injection Sub
3 4,054’ 4.875” 6.540” Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930’-
8945’ 3.375” Owen 4.5 X-Span Patch set 8/14/23
4 9,449’ CIBP, milled and pushed to 9,454’ CTM
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” TOC @ 4,212’ (CBL 04/21/23)
6-3/4”
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
T81
Updated by DMA 05-10-24
PROPOSED
Ninilchik Unit
Paxton 12
API: 50-133-20710-00-00
PTD: 223-014
PBTD = 9,454’ / TVD = 8,341’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
Cactus EN-2CCL 11” Hgr, 4.5” EUE lift threads
4” type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T81 8,039’ 8,051’ 6,958’ 6,970’ 12’ 11/20/23 Open
T120 8,625’ 8,645’ 7,531’ 7,550’ 20’ 6/07/23 &
6/28/23 Open
T120 8,645’ 8,665’ 7,550’ 7,569’ 20’ 6/28/23 Open
T140 8,694’ 8,714’ 7,599’ 7,618’ 20’ 8/15/23 Isolated
T145 8,930’ 8,945’ 7,830’ 7,845’ 15’ 5/19/23 Open
T146 8,980’ 9,070’ 7,879’ 7,968’ 90’ 8/20/23 Open
T160 9,484’ 9,504’ 8,373’ 8,392’ 20’ 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 4,054’ 10,011’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 4,062’
T120
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 156’ 3.813” 5.500” SSSV: ONYX-R5E
2 1,515’ 3.870” 4.500” Chemical Injection Sub
3 4,054’ 4.875” 6.540” Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930’-
8945’ 3.375” Owen 4.5 X-Span Patch set 8/14/23
4 9,449’ CIBP, milled and pushed to 9,454’ CTM
6-3/4”
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
T81
Capillary String 3/8” Proposed to Install
Top Bottom
MD 0’ ±8,100’
TVD 0’ ±7,017’
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240112
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
END 1-27 50029216930000 187009 11/16/2023 YELLOWJACKET PERF
KALOTSA 4 50133206650000 217063 9/28/2023 YELLOWJACKET PERF
KALOTSA 8 50133207050000 222003 11/29/2023 YELLOWJACKET PERF
KBU 13-8 50133203040000 177029 11/5/2023 YELLOWJACKET PERF
KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT
KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF
KBU 11-08Z 50133206290000 214044 8/24/2023 AK E-LINE GPT/CIBP/PERF
KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL
KBU 23-05 50133206300000 214061 10/10/2023 AK E-LINE PLT
KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/PERF
MPU I-01 50029220650000 190090 11/18/2023 YELLOWJACKET PERF
PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF
PAXTON 7 50133206430000 214130 9/18/2023 YELLOWJACKET CBL
PAXTON 7 50133206430000 214130 10/7/2023 YELLOWJACKET PERF
SRU 224-10 50133101380100 222124 12/27/2023 YELLOWJACKET GPT-PLUG-PERF
SRU 224-10 50133101380100 222124 11/4/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT
SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT
SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF
SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL
Please include current contact information if different from above.
T38273
T38275
T38277
T38278
T38279
T38280
T38280
T38281
T38282
T38283
T38284
T38285
T38286
T38287
T38288
T38288
T38289
T38289
T38289
T38290
T38290
1/18/2024
T38287
PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.01.18
11:52:00 -09'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________
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 10,012 feet N/A feet
true vertical 8,892 feet N/A feet
Effective Depth measured 9,449 feet N/A feet
true vertical 8,338 feet N/A 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 4,062' MD 3,223' TVD
Packers and SSSV (type, measured and true vertical depth) N/A N/A 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:
7,500psi
2,980psi
6,890psi
8,430psi
4,292' 3,392'
Burst Collapse
1,410psi
4,790psi
Production
Liner
5,957'
Casing
Structural
8,891'10,011'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
4,292'
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-014
50-133-20710-00-00
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:
Private
Ninilchik / Beluga-Tyonek Gas
Ninilchik Unit Paxton 12
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
126
Size
120'
0 10010505
0 10452
2053
Jake Flora, Operations Engineer
323-612
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
2490
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
jake.flora@hilcorp.com
907-777-8442
N/A
p
k
ft
Fra
O
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6. A
t
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 8:29 am, Nov 28, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.11.27 11:28:47 -
09'00'
Noel Nocas
(4361)
Rig Start Date End Date
E-Line 11/20/23 11/20/23
11/20/2023 - Monday
MIRU Yellowjacket Eline. PT PCE 250 psi Low/ 3000 psi High. RIH w. CCL/GAMA/ 2" Geo gun 6 spf, 60 deg. phasing.
Gun #1 8044'-8044'. Initial/5/10/15 min pressure readings 700/1600/1680/1680 psi.
Gun #2 8039'-8051' Initial/5/10/15 min pressure readings 1800/1950/2175/2225 psi.
Hand well over to operations. Well on line... 8.7mm / 2122 psi
Daily Operations:
Hilcorp Alaska, LLC
Well Operations Summary
API Number Well Permit NumberWell Name
Paxton 12 50-133-20710-00-00 223-014
Gun #2 8039'-8051' Initial/5/10/15
Gun #1 8044'-8044'. Initial/5/10/15 min
Updated by DMA 11-22-23
SCHEMATIC
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,454 / TVD = 8,341
TD = 10,012 / TVD = 8,892
RKB to GL = 18
Cactus EN-2CCL 11 Hgr, 4.5 EUE lift threads
4 type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T81 8,039 8,051 6,958 6,970 12 11/20/23 Open
T120 8,625 8,645 7,531 7,550 20 6/07/23 &
6/28/23 Open
T120 8,645 8,665 7,550 7,569 20 6/28/23 Open
T140 8,694 8,714 7,599 7,618 20 8/15/23 Isolated
T145 8,930 8,945 7,830 7,845 15 5/19/23 Open
T146 8,980 9,070 7,879 7,968 90 8/20/23 Open
T160 9,484 9,504 8,373 8,392 20 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16 Conductor Driven
to Set Depth 84 X-56 Weld 15.01 Surf 120
7-5/8" Surf Csg 29.7 L-80 CDC 6.875 Surf 4,292
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958 4,054 10,011
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958 Surf 4,062
T120
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 156 3.813 5.500 SSSV: ONYX-R5E
2 1,515 3.870 4.500 Chemical Injection Sub
3 4,054 4.875 6.540 Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930-
8945 3.375 Owen 4.5 X-Span Patch set 8/14/23
4 9,449 CIBP, milled and pushed to 9,454 CTM
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2 TOC @ 4,212 (CBL 04/21/23)
6-3/4
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
T81
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?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number):10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
10,012'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
Jake Flora, Operations Engineer
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
12.6# / L-80 4,062'
November 20, 2023
N/A; N/A N/A; N/A
See Schematic See Schematic Tieback 4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Private
223-014
50-133-20710-00-00
Ninilchik Beluga-Tyonek Gas Same
CO 701F
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Paxton 12
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
8,892'9,449'8,338'~2679psi N/A
MD
2,980psi
6,890psi
120'
3,392'
120'
4,292'
Perforation Depth MD (ft):
5,957'4-1/2"
16"
7-5/8"
120'
4,292'
8,430psi8,891'10,011'
m
n
P
s
t
66
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 12:40 pm, Nov 14, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.11.13 11:40:27 -
09'00'
Noel Nocas
(4361)
323-612
DSR-11/15/23
10-404
OBSOLETE FORM USED SFD
Perforate
BJM 11/15/23
November 20, 2023
SFD 11/16/2023*&:JLC 11/16/2023
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.11.16 15:22:48
-09'00'11/16/23
RBDMS JSB 111723
Well Prognosis
Well Name: Paxton 12 API Number: 50-133-20710-00-00
Current Status: Gas Producer Permit to Drill Number: 223-014
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: 3466 psi @ 7879’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2679 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: Online Gas Producer: 2400 mcfd @ 104 psi, 50 bwpd
Brief Well Summary:
Paxton 12 is a 2023 new drill that tested multiple Tyonek zones before being completed as a producer in the
Tyonek 120 & 140 sands. The 140 was later patched and the T-146 perforated and brought online. Currently
the well is just at the unload rate.
The objective of this sundry is to increase the productivity by adding the T-81 sand.
Wellbore Conditions:
05/18/23 Plug set over the T160 @ 9459’
08/14/23 Patch set over the T140 sand 8930-8945’
08/20/23 T146 perforated 8980-9070’
Procedure:
1. Review all approved COAs
2. RU E-line, PT lubricator to 3000 psi
3. Perforate and test the below sand:
Sand MD TOP MD Base TVD TOP TVD Bot
T81 8039’ 8051’ 6958’ 6970’
a. All sands lie in the NINILCHIK UNIT, BELUGA-TYONEK GAS POOL
b. If any zone produces sand and/or water or needs isolated, depress water with nitrogen, RIH
and set plug above the perforations OR patch across the perforations.
4. RDMO
5. Turn well over to production & flow test well
Attachments:
1. As-built Well Schematic
2. Proposed Well Schematic
3. Standard Nitrogen Operations
4. AOGCC RWO Change Form
Updated by CJD 08-31-23
SCHEMATIC
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,454’ / TVD = 8,341’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
Cactus EN-2CCL 11” Hgr, 4.5” EUE lift threads
4” type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T120 8,625’ 8,645’ 7,531’ 7,550’ 20’ 6/07/23 &
6/28/23 Open
T120 8,645’ 8,665’ 7,550’ 7,569’ 20’ 6/28/23 Open
T140 8,694’ 8,714’ 7,599’ 7,618’ 20’ 8/15/23 Isolated
T145 8,930’ 8,945’ 7,830’ 7,845’ 15’ 5/19/23 Open
T146 8,980’ 9,070’ 7,879’ 7,968’ 90’ 8/20/23 Open
T160 9,484’ 9,504’ 8,373’ 8,392’ 20’ 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 4,054’ 10,011’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 4,062’
T120
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 156’ 3.813” 5.500” SSSV: ONYX-R5E
2 1,515’ 3.870” 4.500” Chemical Injection Sub
3 4,054’ 4.875” 6.540” Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930’-
8945’ 3.375” Owen 4.5 X-Span Patch set 8/14/23
4 9,449’ CIBP, milled and pushed to 9,454’ CTM
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” TOC @ 4,212’ (CBL 04/21/23)
6-3/4”
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
Updated by DMA 11-06-23
PROPOSED
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,454’ / TVD = 8,341’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
Cactus EN-2CCL 11” Hgr, 4.5” EUE lift threads
4” type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T81 ±8,039’ ±8,051’ ±6,958’ ±6,970’ ±12’ Proposed TBD
T120 8,625’ 8,645’ 7,531’ 7,550’ 20’ 6/07/23 &
6/28/23 Open
T120 8,645’ 8,665’ 7,550’ 7,569’ 20’ 6/28/23 Open
T140 8,694’ 8,714’ 7,599’ 7,618’ 20’ 8/15/23 Isolated
T145 8,930’ 8,945’ 7,830’ 7,845’ 15’ 5/19/23 Open
T146 8,980’ 9,070’ 7,879’ 7,968’ 90’ 8/20/23 Open
T160 9,484’ 9,504’ 8,373’ 8,392’ 20’ 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 4,054’ 10,011’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 4,062’
T120
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 156’ 3.813” 5.500” SSSV: ONYX-R5E
2 1,515’ 3.870” 4.500” Chemical Injection Sub
3 4,054’ 4.875” 6.540” Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930’-
8945’ 3.375” Owen 4.5 X-Span Patch set 8/14/23
4 9,449’ CIBP, milled and pushed to 9,454’ CTM
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” TOC @ 4,212’ (CBL 04/21/23)
6-3/4”
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
T81
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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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 09/12/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230912
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 18RD 50133205840100 222033 9/6/2023
YELLOW
JACKET GPT-PERF
BCU 18RD 50133205840100 222033 8/24/2023
YELLOW
JACKET PLUG
BCU 18RD 50133205840100 222033 8/28/2023
YELLOW
JACKET PLUG-PERF
BCU 18RD 50133205840100 222033 9/9/2023
YELLOW
JACKET PLU-GPT-PERF
BCU 18RD 50133205840100 222033 9/4/2023
YELLOW
JACKET SCBL
BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL
BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf
BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf
BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT
IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf
IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf
KTU 43-6XRD2 50133203280200 205117 9/4/2023
YELLOW
JACKET CALIPER
KU 42-12 50133206890000 220045 8/31/2023
YELLOW
JACKET GPT-PERF
KU 42-12 50133206890000 220045 8/20/2023
YELLOW
JACKET SCBL
MPU E-23 50029225700000 195094 8/18/2023
YELLOW
JACKET CBL-PLUG
MPU E-23 50029225700000 195094 8/20/2023
YELLOW
JACKET PERF
Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf
Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf
PBU L-240 50029237030000 221086 8/30/2023 READ IPROF
Please include current contact information if different from above.
T37983
T37983
T37983
T37983
T37983
T37984
T37984
T37984
T37985
T37986
T37987
T37988
T37989
T37989
T37990
T37990
T37991
T37991
T37992
9/13/2023
Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf
Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.09.13
10:28:30 -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): Ninilchik Unit
GL: 148.6' BF:N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" X-56 120'
7-5/8" L-80 3,392'
4-1/2" L-80 8,891'
4-1/2" L-80 3,220'
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
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
4,062'
Surface
4,292'
12.6#
Surface
4-1/2"
SIZE DEPTH SET (MD)
4,054' MD / 3,216' TVD
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
4,054' 10,011'
Surface
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 - 455 sx / T - 98 sx6-3/4"
9-7/8"
Driven
Surface L - 625 sx / T - 173 sx
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
4/27/2023 223-014 / 323-210
SETTING DEPTH TVD
2227311
TOP HOLE SIZE
CBL 4-22-23, Perf/Tie In Logs, Mudlogs, XMRI, LWD (AGR, PWD, EWR-P4, DDSR, ALD, CTN)
N/A
N/A
156' MD / 156' TVD
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
206234 2230533
50-133-20710-00-00March 20, 2023
LOCI 04-007
Paxton 12April 2, 2023832' FNL, 3092' FEL, Sec 13, T1S, R14W, SM, AK
166.6
Beluga - Tyonek Gas Pool
Private
10,012' MD / 8,892' TVD
9,454' MD / 8,341' TVD
1494' FSL, 612' FWL, Sec 13, T1S, R14W, SM, AK
CASING, LINER AND CEMENTING RECORD
Gas-Oil Ratio:
AMOUNT
PULLED
204587
204428
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
2227528
1273' FSL, 457' FWL, Sec 13, T1S, R14W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
4,062'
3,216'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
5/23/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
0112143 111
8/26/2023 24
Flow Tubing
112
3351
N/A33510
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 10:03 am, Aug 31, 2023
Completed
4/27/2023
JSB
RBDMS JSB 091123
GDSR-9/18/23
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval 8,625' Ty 120 7,531'
718' 718'
1017' 1012'
4736' 3761'
4862' 3874'
6830' 5781'
7653' 6581'
8328' 7240'
8625' 7531'
8667' 7572'
8904' 7805'
8961' 7860'
9273' 8167'
9914' 8796'
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:
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
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Ty 200
Ty 140
Ty 2
ST 3
Ty 40
Ty 120
Bel A
Bel 136
Ty 60
Ty 100
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.
Ty 145
Ty 146
Ty 160
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports
Authorized Title: Drilling Manager
Formation Name at TD:
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
08/31/23
Monty M
Myers
Updated by CJD 08-31-23
SCHEMATIC
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,454’ / TVD = 8,341’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
Cactus EN-2CCL 11” Hgr, 4.5” EUE lift threads
4” type H BPV profile
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T120 8,625’ 8,645’ 7,531’ 7,550’ 20’ 6/07/23 &
6/28/23 Open
T120 8,645’ 8,665’ 7,550’ 7,569’ 20’ 6/28/23 Open
T140 8,694’ 8,714’ 7,599’ 7,618’ 20’ 8/15/23 Isolated
T145 8,930’ 8,945’ 7,830’ 7,845’ 15’ 5/19/23 Open
T146 8,980’ 9,070’ 7,879’ 7,968’ 90’ 8/20/23 Open
T160 9,484’ 9,504’ 8,373’ 8,392’ 20’ 4/27/23 Isolated 5/18/23
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” 4,054’ 10,011’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf 4,062’
T120
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 156’ 3.813” 5.500” SSSV: ONYX-R5E
2 1,515’ 3.870” 4.500” Chemical Injection Sub
3 4,054’ 4.875” 6.540” Seal stem, XO, Liner hanger / ZXP LTP Assembly
3.1 8930’-
8945’ 3.375” Owen 4.5 X-Span Patch set 8/14/23
4 9,449’ CIBP, milled and pushed to 9,454’ CTM
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” TOC @ 4,212’ (CBL 04/21/23)
6-3/4”
hole
3
2
1
4, 5
T140, isolated w patch 8/14/23, ID 3.375in
T146
T160
T145
3.1
Activity Date Ops Summary
3/15/2023 Cont RD for move, prep office trailers for transport, removed HCR valve cluster from BOP stack, spot crane at 09:00 and transfer BOP stack from cellar to
cradle, Thaw brakes on sleeper trailer and have three trailers on the road at 10:30 headed to Paxton. Removed hooch over top of centrifuge, tore. service
shacks, load various equipment and available rig mats, light plant, heater, bang box. Transport gen and equipment to Paxton. Crane removed clam shell from rig
floor. Shipped BOP stack, service shacks, rig mats, pipe racks to Paxton. Performed mast inspection prior to laying over, laid over mast. R/D air, water, and
steam lines, blew down same. Lowered degasser into pit #4. Staged office trailers on Paxton, set bang box and wired in and powered up office trailers, and
installed comm's at office trailers. Removed windwalls and choke house, lowered pit roof tops. Removed centrifuge. Staged catwalk and poorboy degasser skid
for move. R/D electrical to MP's and mud pits. *Notified by Swanson Production of a vehicle accident in field at approximately 16:30, field Electrician leaving the
field lost control and made contact with CCI night crew truck enroute to rig's location. No injuries. Notified Drilling Engineer and Hilcorp Safety Rep*. Shipped
choke house, windwalls, aux fuel tank and gen #3 to Paxton pad, shipped exposed rig mats, centrifuge, connex's. Off loaded 800 gals of fuel from rig to fuel
truck. Vacuumed out water from boiler hot well tank and rig water tank. Cut & folded up misc. pieces of liner from exposed rig foot print and disposed of felt into
dumpster. Loaded out float w/ rig mats, jig from between pits & MP's, and oil drum containers. Disposed of oily waste in field. Lowered doghouse in rig water
tank. Folded up walkways on gen skid. Loaded out pipe bunk and hauled to staging pad. Wrapped dry hole tree w/ liner and put Tioga heater on it. Loaded out
floats w/ sub peg board, oily waste totes, knack box, TQ bushing, Handy berm &. CCI conex, and staged to be moved to Paxton. Prepped mast to be picked w/
cranes. Crew change. Night crew traveled to Paxton pad to lay felt, liner, and set rig mats. Then traveled back to Swanson River to cont. organizing pad and
prepping to move remainder of rig at 07:00 hrs. CCI rig support cont. loading out misc. equip & tools onto floats.
3/16/2023 Cont clean up felt and liner at 231-33, CCI on location at 07:00. Tore out mud pump #1, boiler skid and HPU skid. RD change/safety shacks. Load mats and
connex's, staged small crane and lowered derrick board windwalls, wait on arrival of 2nd crane and return of trucks from Paxton. Night crew traveled to Paxton to
cont laying rig mats, 2nd crane on location at 10:30 and staged to pick derrick, trucks on location at 11:30, set derrick bolsters on trailer and staged for loading.
Loaded gen skid and pump #1, picked derrick and drill line spool off carrier, picked carrier off sub, secured handrails and folded up stairs/walkways on sub.
Picked sub off pony walls, loaded pony walls on trailer with mats. Shipped mats, pony walls, HPU, cranes and sub to Paxton. Derrick and. pump #1 on the
highway at 16:30. Received tree for 231-33 and wellhead rep on location to install with CCI loader and couple rig hands. Transported shop and two pit modules
to Paxton, set last of rig mats and start thawing/clearing mats of ice. Truck Pusher decided not to attempt setting sub base due to high wind, will see if wind dies
down overnight. WHR & rig hands finished N/U tree on SRU 231-33, re-wrapped tree w/ liner. and put Tioga heater on well. Removed 10' mat next to cellar and
installed 10' x 20' mat. Set pony subs, set iron roughneck HPU & heater between pony walls. lowered walkways, stairs, and installed handrails on sub. Raised
handrails and installed lights on choke house, dog house, and sun deck. Installed lights on roof of pump house, gen skid, and pits. Crew change. Currently
waiting on wind to die down to set sub, carrier, and mast with cranes.
3/17/2023 Waiting on high wind to subside for setting sub base on pony walls. Staged cranes and sub base on rig mats in prep to set sub as soon as we get a break in
wind. Stage rig modules in prep to start assembly of rig as soon as sub, drawworks and derrick in place. Transported safety/change shacks to. Paxton, set
mechanic shop and safety/change shacks, wired in and powered up same. Bermed camp gen, thawed sewer cleanout valves on sleeper and change shack.
Heavy snow and gusts to 40 mph. CCI removed sub base from trailer (still staged on mats), C/O pump liners to 5 1/2", C/O fuel pump on fuel cube, transported
barrel warmer and electrician shop, Received dumpsters, transported rig forklift to Paxton. Transported casing tongs and power packs to PESI. Wind changed
and significantly. reduced. Called out crane crew and rig movers at 17:30. Gave AOGCC 72 hour notice for diverter function test at 12:30 pm. Updated all
service reps of rig move and RU status. Shoveled snow off rig mats. CCI rep on location at 19:00, remainder of crew on location at 19:30. Set sub, carrier, and
mast. Spotted doghouse/rig water tank. Flew IR to rig floor w/ crane and pinned in place. Spotted rig HPU module. Raised V-door wind wall on rig floor w/ crane
and pinned in place. Erected derrick board house wind walls w/ crane. Raised dog house. Spotted pit module #1, set jig. Spotted & set pit modules 2 & 3, and
MP 1 & 2 too jig. Raised roofs on pits, set gen 1 & 2 skid. Flew choke house w/ crane and hung on ODS. Set centrifuge w/ crane. Set boiler house w/ winch
truck. Started R/U electrical lines and TD HPU lines. Worked on hanging wind walls w/ crane. Crew change, held PTSM. Fired gen, powered up lights. Finished
hanging wind walls w/ crane. Prepped to raise mast, stood mast. Set clam shell on back side of mast w/ crane. Released CCI crane operators & movers at 01:30
hrs. Put Tioga heater in boiler house to warm up boilers. Patched in liner for. catwalk and set rig mats. Raised degasser in pit #4, R/U jumper lines in pits.
Spotted and set service shacks. Filled boiler with water and fired, currently staging up boiler. Spotted and set CCI conex. Working jumper lines in pump room.
Set diverter bag in sub. Spotted & set auxiliary fuel tank and. gen #3. Cont. working on R/U electrical lines. R/U tarps around rig. Started pulling Pason cables
throughout rig.
18
n (LAT/LONG):
evation (RKB):
50-133-20710-00-00API #:
Well Name:
Field:
County/State:
NINU Paxton 12
Ninilchik
Hilcorp Energy Company Composite Report
, Alaska
3/20/2023
Contractor
AFE #:
AFE $:
231-00047
$5,512,500
Job Name:231-00047 Paxton 12 Drilling
Spud Date:
3/18/2023 Set gen 3, cont RU pit interconnects, CCI crane operator on location at 09:00 and set poorboy degasser skid, installed hooch over centrifuge, set catwalk,
plugged in service shacks, set upright water tank for cement water, laid over beaver slide, staged, diverter T and flow riser in cellar. Installed pump suction lines
and shock hose to carrier, set stairs off pit #2, RU rig's HPU, choke house lines to pit's. Loader operator found a glycol spill at driveway entrance to pad, made
notifications and cleaned it up. Production vac truck had hose failure. Operator retrieved bags for disposal. RU comms to service shacks, added water to rig tank
and start circulating through system, prep upper torque tube for derrick scope, RU camera system, Handy Berm on location berming rig footprint, took on rig fuel,
spooled up drill line, held PJSM, scoped up derrick. Set mud docks. Lowered blocks and stowed bridle lines, installed T-bar. R/U TD lifting devices. Tailed TD &
cradle to rig floor. R/U dog bone on TD to blocks. Installed TQ bushing on TD. Adjusted service loop sock, R/U service loop & Kelley hose to TD. R/U centrifuge
electrical and function tested. Cont. working. through rig acceptance check list. R/U centrifuge slide and cutting shoots. Replaced damaged steam hoses. Got
steam circulating throughout the rig. Worked on unloading mud products and building mud docks. Crew change, held PTSM. Cont. R/U TD. Hooked up HYD
lines on TD. Installed bails & link tilt cylinders. Function tested TD HPU and robotics on TD (ok). R/U ODS handrails & tarps. Installed mast cylinder covers.
Changed out grabber box dies, R/U tongs. Performed derrick inspection. R/U power cord. for derrick heater and lights. Secured Pason cable to derrick ladder.
Function tested auxiliary equip. for MP's. Filled liner wash reservoir. Function tested MP throttle. Hooked up accumulator lines to accumulator house. R/U iron
roughneck HPU and function tested iron roughneck. Tested all. accumulator bottles. Average = 1043 psi. Back up bottles = 2450 psi. R/U Geronimo line,
installed saver sub. Function tested E-choke. Adjusted load collar on TD. Removed inspection hatch on degasser and power washed inside of vessel. Started
bring on water and performing hydro test to pits. Dressed shakers. Spotted & set CCI's hurricane vac. Greased and inspected- blocks, wash pipe, TD, crown,
DWKS, brake linkage, and drive shaft. Hauled: 0 bbls Solids to KGF G&I. Cumulative: 0 bbls. Hauled: 0 bbls Fluid to KGF G&I. Cumulative: 0 bbls. Hauled: 0 bbl
Cement to KGF G&I. Cumulative: 0 bbl. Lost: 0 bbl Fluid Down Hole. Cumulative: 0 bbl. Daily Metal: 0 lbs. Cumulative: 0 lbs.
3/19/2023 Set wear ring and run tool in wellhead, NU DSA, diverter T, annular, flow riser and knife valve. Checked end play on topdrive (ok), removed auto choke from
manifold (won't function), Offload mud product, move water throughout pits and check for leaks, check PVT calibrations. Install knife valve. Test ran centrifugal
pumps, hole fill pump, agitators, dressed shakers. Changed oil in agitators and topdrive swivel. Updated AOGCC Rep and Quadco for test time, Gyro data and
Ak E-line for PU tools time. Function tested mud pumps, secured stack with 4 way chains, installed vent line and anchors and pulled measurements, installed
auto choke in manifold, set cement silo, installed ball valve on conductor outlet, started building spud mud. Installed catch liner from rotary table to flow riser.
Functioned ESD's, trouble shot and fixed ESD on mud motor. Installed elevators on bails. Cleaned and organized rig, location, and conex's. Fixed lights on top
of mud pits. Cont. building spud mud. Installed heat trace on mud lines. Pressure. tested surface lines to 1900 psi (ok). Blew down TD. Function tested annular
& knife valve. Opening/closing times. Knife valve opening time = 2 sec, Annular closing time = 26 sec. Finished rig acceptance check list. Accepted rig on 3-20
@ 00:00 hrs. P/U test jt. Removed test plug from well. Installed rotary table mouse hole for P/U DP. Crew change, held PTSM. Finished building 300 bbls of 8.8
ppg spud mud. Prepped rig floor for P/U 4.5" DP. Loaded catwalk w/ 4.5" DP. Strapped & tallied 4.5" CDS 40 DP. Currently P/U 4.5 DP singles off the walk,
building stds, and racked back in the derrick.
3/20/2023 Cont PU and rack back total 73 stands 4 1/2" DP and 8 stands 4 1/2" HWDP. Quadco Rep checked gas alarms and calibrated weight indicator and casing
gauge in doghouse. Shipped out landing joints and bed truck. Built another 100 bbls spud mud so we can use vacuum degasser. AOGCC Rep on location at
12:00. Quadco tested audio/visual gas alarms and was released, rig performed diverter function test with no issues. Sent test form, vent line drawing with
measurements of potential ignition sources and pictures to AOGCC Rep Jim Regg, received verbal approval to spud. Paxton 12 via telephone at 13:15. Flooded
stack with spud mud, no leaks. *Annular close time = 28 sec, knife open time = 2 sec. Spotted Ak E-Line unit and GyroData on location at 13:30. PU and MU 9
7/8" Kymera jetted with 1x9, 2x10's, 2x14's, 2x18's for TFA of 1.0132, on 6 3/4" mud motor w/1.5 bend. MU DM collar and EWR-M5 collar, scribe same with an
RFO of 58.66. MU and orient UBHO sub. Plugged in and uploaded MWD. PU RIH with 1 jnt NM flex DC, MU XO and 1st stand HWDP. S/O and tagged bottom
at 120', PU and break circ. Recieved 90 jnts 7 5/8" casing, removed protectors and start drifting same. Circ at 408 gpm-856 psi, 40 rpm-1640 ft/lbs off bott
torque, spudded well at 17:16 and drilled from 120' to 172' at 130 ft/hr ROP. Racked back stand HWDP, PU 2nd jnt NM flex DC, MU stand HWDP. Held PJSM
with e-line and gyrodata, hung sheave in derrick, RIH w/ gyro tool on E-line, obtained check. w/ Gyro tool @ 172'. POOH, check compression tattle tail, had good
indication we were set down inside UBHO tool correctly with Gyro tool. Cont. drilling ahead F/172'-T/393' taking check shots every connection w/ Gyro tool and
correlating them back to MWD surveys. P/U-35K S/O-33K ROT-35K. GPM-410 SPP-1033 psi TQ-1.6K Max gas 2 units MW-8.85 ppg ECD-9.7 ppg. Off line
Finished, drifting, strap, and tally 89 jts w/ one bad one. Crew change, held PTSM. Cont. drilling/sliding ahead F/393'-T/699' taking check shots every connection
w/ Gyro tool and correlating them back to MWD surveys. P/U-43K S/O-46K ROT-45K GPM-408 SPP-959 psi TQ-1.9K Max gas 27 units MW-8.85 ppg ECD-9.4
ppg K-Revs= 8. Distance to well plan. 3.58' 2.27' Low 2.76' Left. Last survey we were 18' projected from Paxton 9 at the bit. Hauled 64 bbls solids to G&I.
Cumulative Hauled = 64 bbls. Hauled 16 bbls trash fluid to G&I. Cumulative Hauled = 16 bbls. Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls. Daily
Downhole Losses = 0 bbls. Cumulative Losses = 0 bbls. Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/21/2023 Cont. drilling/sliding ahead F/ 699'-T/ 887' taking check shots every connection w/ Gyro tool and correlating them back to MWD surveys. P/U-45K S/O-49K ROT-
49K GPM-450 SPP-1350 psi TQ-3K Max gas 40 units MW-8.85 ppg ECD-9.4 ppg. Confirm with MWD and DD on correlation with town team also. Prognosed to
be 60' away from Paxton 6 at +/- 1300' md. Discuss results with ODE and confirmation acquired to release Gyro and R/D E-Line. Backream last stand drilled T/
887' and R/D E-Line. Continue drilling ahead in 9-7/8" Surface hole F/ 887' T/ 1195' GPM 450 SPP 1450 PSI TQ 3K WOB 7K ECD 9.51ppg Max gas 100 units.
P/U 57K, S/O 53K, ROT 50K. CBU GPM 450 SPP 1329psi and clean up well. Monitor well, POOH F/1195' T/ 327' and lower jar stand back in hole. P/U 57K S/O
53K. Grease Crown, Blocks, Wash Pipe, Top Drive, Iron Roughneck, Draworks, Driveline and Inspect Brake Linkage. Level up subbas e. RIH on elevators F/327'-
T/1195' w/ no issues or fill on bottom. Had calculated pipe displacement for the trip. P/U-57K S/O-53K. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet, sweep
came back on time w/ a 20% increase in cuttings. Cont. drilling/sliding 9-7/8" surface hole F/1195'-T/1567'. P/U-53K S/O-50K ROT-52K GPM-450 SPP-1620 psi
TQ-3/4K WOB-7K RPM-50 Max gas 104 units MW-8.9 ppg ECD-9.73 ppg. Crew change, held PTSM. Cont. drilling/sliding 9-7/8" surface hole F/1567'-T/1935'.
P/U-57K S/O-52K ROT-55K GPM-450 SPP-1605 psi TQ-4.5K WOB-7-14K RPM-50 Max gas 104 units MW-9.05 ppg ECD-9.68 ppg K-Rev = 24 Distance
to well plan. 4.68' .22' Low 4.67' Right. Hauled 171 bbls solids to G&I. Cumulative Hauled = 235 bbls. Hauled 144 bbls trash fluid to G&I. Cumulative Hauled
=160 bbls. Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls. Daily Downhole Losses = 0 bbls. Cumulative Losses = 0 bbls. Daily Metal Recovered = 0
lbs. Cumulative Metal Recovered = 0 bbls.
3/22/2023 Cont. drilling/ Sliding as needed 9-7/8" surface hole F/1935' T/1999' GPM-450 SPP-1760 psi TQ-4K WOB-7K RPM-50 Max gas 92 units MW-9.05 ppg ECD-
9.58 ppg P/U 60K S/O 52K ROT 56K. Pason system acting up, Pull wiper trip and move antenna F/ Pushers shack T/ DSM shack as per Pason Tech. Monitor
well, Static. POOH F/1999' T/1130' with no overpulls observed. P/U 50K S/O 50K, Calculated Fill 6.9 BBLs, Actual 7.6 BBLs. While moving Pason antenna.
Confirm Pason system working properly. Good. Grease Crown, Blocks, Wash Pipe, Top Drive, Iron Roughneck, Draworks, Driveline and Inspect Brake Linkage.
Clean out mud pump screens 60% Packed off. MP Annular PSI. MP1 500psi, MP2 700psi. RIH F/1130' T/1999' washing last stand down with no problems. P/U
50K S/O 50K, Calculated Displacement 18.3 BBLs, Actual 18.4 BBLs. Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/ 1999' T/ 2032' sending Hi-Vis
sweep that came back 100 strokes late with 10% increase in cuttings. GPM 460, SPP 1860psi, RPM 50, TQ 5K, WOB 15K, ECD 9.73ppg, Bottom up gas at 150
units. P/U 60K, S/O 52K, ROT 56K. Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/ 2032' T/ 2375' GPM 460, SPP 1885psi, RPM 50, TQ 5-7K, WOB
12-15K, ECD 9.94ppg, Max gas at 250 units. P/U 69K, S/O 52K, ROT 56K. Cont. drilling/sliding 9-7/8" surface hole F/2375'-T/2745'. P/U-67K S/O-55K ROT-57K
GPM-455 SPP-1975 psi TQ-5/6K WOB-15/19K RPM-50 Max gas 128 units MW-9.35 ppg ECD-10.07 ppg. Crew change, held PTSM. Cont. drilling/sliding 9-7/8"
surface hole F/2745'-T/3130'. P/U-76K S/O-57K ROT-65K GPM-455 SPP-2037 psi TQ-6.5K WOB-15/21K RPM-50 Max gas 117 units MW-9.45 ppg ECD-10.08
ppg K-Revs = 52K Distance to well plan. .66' .59' High .30' Left. Hauled 96 bbls solids to G&I. Cumulative Hauled = 331 bbls. Hauled 299 bbls trash fluid to
G&I. Cumulative Hauled =459 bbls. Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls. Daily Downhole Losses = 0 bbls. Cumulative Losses = 0 bbls.
Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/23/2023 Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/ 3130' T/ 3175' GPM 450, SPP 2025psi, RPM 50, TQ 5-7K, WOB 15-20K, ECD 10.2ppg, Max gas at
45 units. MW in 9.45 MW out 9.5 P/U 75K, S/O 57K, ROT 65K. Circulate STS and assure hole is clean. Take check shot with MWD. Flowcheck well, Static.
POOH F/ 3175' T/ 2125' P/U 82K S/O 56K. No overpulls observed during trip. Calculated Fill 6.9 BBLs, Actual Fill 7.7 BBLs. Service Blocks, Top Drive, Iron
Roughneck, Draworks, Gear box, Drive Line, Floor Motor, Brake Linkage and clean pump screens. Monitor well on trip tank with no gains or losses. RIH F/ 2125'
T/ 3115' P/U 82K S/O 56K. No set downs during trip. Calculated displacement 18.3 BBLs, Actual displacement 16.9 BBLs. Connect last stand to Top Drive and
fill pipe, Send Hi-Vis sweep and reciprocate and wash last stand down T/ 3175' and circulate sweep out of hole. Bottoms up gas at 220 units, Sweep came back
on time with no increase in cuttings. Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/ 3175' T/ 3301' GPM 500, SPP 2450psi, RPM 50, TQ 5-7K, WOB
15-21K, ECD 9.97ppg, Max gas at 80 units. MW in 9.45 MW out 9.5 P/U 80K, S/O 68K, ROT 68K. Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/
3301' T/ 3616' GPM 450-500, SPP 1992-2415psi, RPM 50, TQ 5-7K, WOB 15-21K, ECD 9.85-10ppg, Max gas at 40 units. MW in 9.45 MW out 9.5 P/U 83K,
S/O 63K, ROT 68K. Cont. drilling/sliding 9-7/8" surface hole F/3616'-T/3889'. P/U-95K S/O-65K ROT-75K GPM-480 SPP-2082 psi TQ-6/7K WOB-21K RPM-50
Max gas 80 units MW-9.2 ppg ECD-9.57 ppg. Crew change, held PTSM. Cont. drilling/sliding 9-7/8" surface hole F/3889' to current depth of 4235'. P/U-97K S/O-
66K ROT-76K GPM-486 SPP-2352 psi TQ-7.2K WOB-21K RPM-50 Max gas 167 units MW-9.3 ppg ECD-9.87 ppg K-Revs = 86K Distance to well plan.
13.97' 7.44' Low 11.38' Left. Hauled 137 bbls solids to G&I. Cumulative Hauled = 468 bbls. Hauled 533 bbls trash fluid to G&I. Cumulative Hauled =992 bbls.
Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls. Daily Downhole Losses = 0 bbls. Cumulative Losses = 0 bbls. Daily Metal Recovered = 0 lbs.
Cumulative Metal Recovered = 0 bbls.
3/24/2023 Continue Drilling/ Sliding as needed 9-7/8" Surface hole F/ 4235' T/ 4279' MD 3395' TVD GPM 485, SPP 2320psi, RPM 50, TQ 7.6K, WOB 22K, ECD 9.74ppg,
Max gas at 175 units. MW in 9.25 MW out 9.35 P/U 97K, S/O 66K, ROT 76K. Krevs = 88K Distance to well plan: 17.01' 5.38' High 16.14' Left. CBU while
reciprocating and rotating at 485 GPM 2080psi SPP Bottoms up Gas is 50 units. circulate 332 BBLs, Flowcheck well, slight seepage. B/D Top Drive. POOH F/
4297' T/ 3120' with no issues. Calculated Fill 9.2 BBLs Actual Fill 11.5 BBLs. P/U 107K S/O 71K. Service Crown, Blocks, Top Drive, Iron Roughneck, Draworks,
Gear Box, Drive Line, Floor Motor, Brake Linkage and clean out mud pumps suction screens. Monitor well on trip tank, 1 BBL/ Hr static loss rate. RIH F/ 3175' T/
4297', No issues on trip. Install 10' pup between last two stands and wash last stand down with no fill. Calculated Displacement 24.4 BBLs Actual Displacement
21.7 BBLs P/U 107K S/O 71K. Pump 20 BBL Hi-Vis sweep and Pump STS GPM 425 SPP 1725psi. Rotate and reciprocate while pumping sweep. Sweep came
back 400 strokes early (28 BBLs). Flow check well, Slight seepage, POOH F/ 4297' T/ 4000' Laying down 10' pup joint P/U 103K S/O 68K. Level subbase with
Shims. POOH F/ 4000' T/ 701' Standing back Drill Pipe from BHA #1. Two tight spots wiped clean at 3620' and 3183'. PJSM, Stand back 4-1/2" HWDP and
Jars. Stand back flex collars. PJSM and remove sources, Download MWD, Submit 24 hour notice to AOGCC Jim Regg via e-mail with response. L/D UBHO
sub, TM, EWR, DM, Drain and Inspect Motor, Break Bit, Clean, Inspect and Grade BIT 1-1. Calculated Hole Fill 32.86 BBLs Actual Hole Fill 41.0 BBLs. Cleared
& cleaned rig floor. Spotted HES E-line truck, R/U sheaves, M/U logging tools- RWCH, MCEH, MCEJ, GTET, XRMI-I instrument, XRIM-I Mandrel, JLatch, and
Cabbage Head (Total length = (62.62'). Held PJSM w/ HES, rig crew, and DSM. RIH w/ HES logging tools, tagged bottom @ 4293' WLM. POOH logging open
hole at 1800' per/hr. F/4293'-T/305'. Crew change, held PTSM. Finished logging OOH. R/D and released HES E-line. M/U BHA #2, cleanout assy. 9-7/8" bit,
motor, stabilizer, flex collars, jars, and HWDP. RIH F/surface-T/4297', filling pipe every 1500' w/ no issues or fill on bottom. Had calculated pipe displacement for
the trip. Currently CBU. P/U-88K S/O-69K ROT-77K GPM-452 SPP-1493 psi TQ-8.1K RPM-50 Max gas 47 units MW-9.4 ppg. Hauled 42 bbls solids to G&I.
Cumulative Hauled = 510 bbls. Hauled 248 bbls trash fluid to G&I. Cumulative Hauled =1240 bbls. Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls.
Daily Downhole Losses = 0 bbls. Cumulative Losses = 0 bbls. Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/25/2023 Pump Hi-Vis sweep STS. P/U-88K S/O-69K ROT-77K GPM-500 SPP-1715 psi TQ-7K RPM-80 MW in-9.4ppg MW out 9.9ppg. Sweep came back 344 stks early
with no increase in cuttings. Cont. Circ and cond. until 9.4ppg going in and 9.4+ppg coming out. B/D Top Drive, Flowcheck with slight seepage. POOH F/ 4297'
T/ 663' Standing back CDS40 DP in derrick. P/U 96K S/O 70K. POOH with BHA #2 F/ 663' T/ Surface. Stand Back HWDP and L/D Jar, 1 jt of HWDP, 2 Non
mag flex collars, Stabilizer, Motor and Bit. Total hole fill for entire trip. Calculated 34.8 BBLs Actual 43.9 BBLs. Empty pits 1, 4, 5 and 6. 20 BBL blackwater pill in
pill pit. Remove unneeded crossovers from rig floor. Clean and Clear rig floor, Pull wear ring, Remove crossovers from catwalk, P/U 47 centralizers onto rig floor,
P/U casing handling equipment, R/U casing tongs and R/U fill up line and load casing. PJSM, P/U and Baker-Lok 7-5/8" Shoe track and confirm floats working
as designed, Good. Continue RIH with 7-5/8" 29.7# L-80 BTC Casing F/ 122' T/ 4272' Torqueing connections to 8K ft/lbs. Filling on the fly and topping off every
ten. P/U & M/U Hanger/ LJ. 5' hanger in, landed hanger on seat. M/U. drive sub. Broke circ. Dry- P/U- 140K S/O-80K Wet- P/U-125K S/o-80K Submit 24 hour
notice to AOGCC for BOPE Test @ 15:30. Circulated & conditioned mud for cement job while MIRU HES cementers. R/D casing handling equip. R/U bail
extensions, P/U cement head, loaded cement plugs, R/U 1502 cement hoses. P/U-125K S/O-80K GPM-168 SPP-139 Max gas 41 units MW-9.4 ppg. Crew
change, held PTSM. Cont. circ. & conditioning mud while R/U HES cementers. Landed hanger on seat, shut down MP, loaded plugs in cement head. M/U
cement head and 1502 hoses. Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested lines at 340 psi. low 3900 psi high,
good tests. Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 5 bpm- 185-150 psi, dropped bottom plug and pumped 268 bbls (625 sx) 12 ppg Type I II lead
cement at 5 bpm- 136-158 psi, followed by 35.5 bbls (173 sx) 15.8 ppg Type I II tail cement at .5-4 bpm- 36-168 psi. Halliburton dropped top plug, then displaced
with 9.4 ppg Spud Mud at 5 bpm 12-663 psi. Slowed pump to 2 bpm with 20 bbl to go. Did bump the plug at 188.5 bbls into displacement (calculated 194 bbls).
Held 1347 psi (FCP of 658 psi) for 3 minutes, bled off and floats held. Bled back 1 bbl to truck. Had 60 bbls of Spacer returns to surface and 98 bbls lead
cement to surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix water temp 76 deg. Pumped 75% excess on lead and 50% excess on tail. Lost 13
bbls throughout the job. Did reciprocate. CIP at 03:50 hrs, 3/26/2023. Drained stack to cellar and flushed w/ black water. Washed up, blew down, R/D, and
released HES cementers. Backed out landing joint. Currently flushing stack with Johnny Wacker. Hauled 25 bbls solids to G&I. Cumulative Hauled = 535 bbls.
Hauled 405 bbls trash fluid to G&I. Cumulative Hauled =1645 bbls. Hauled 0 bbls Cement to G&I. Cumulative Hauled = 0 bbls. Daily Downhole Losses = 0 bbls.
Cumulative Losses = 0 bbls. Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/26/2023 P/U Pack-Off with running tool, Set and RILDS. Test Pack-Off T/ 3000psi. for 15 minutes, Good. Move 8 stands of 4-1/2" HWDP F/ DS Racking Board T/ ODS
Racking Board. N/D Diverter assembly, Vent Line, Anchors, Flow Line, Bell Nipple and Knife Valve. Remove chains from 21-1/4" Annular and N/D Annular
Preventer. Change out 5-1/2" Liners in Mud Pumps T/ 5", Clean Mud tanks #4, #5, #6 and Shakers. Nipple Down TEE and DSA. Raise catwalk slide to remove
Annular. Set crane into place, PJSM, Remove 21-1/4" Annular Preventer, Tee and DSA with crane from substructure. PJSM, Bring in "B" wellhead with crane to
substructure, Lift with cellar cranes and place on starting head. Crane remove 11" 5M BOPE stack from cradle and bring to substructure. Place BOPE stack on
"B" section of well and N/U. Lower catwalk slide back in place. Assemble choke and kill configurations, Flowbox, Flow nipple, Riser & Flowline. Secure BOPE
stack with chains and binders. Grease choke manifold and mud cross valves. Continue cleaning pits. Test Starting head and Lower "B" section flange T/
3000psi. for 15 minutes. Good. Remove unneeded crossover subs from rig floor. Secure BOPE stack with chains and binders. Grease choke manifold and mud
cross valves. Continue cleaning pits. Obtain RKBs. Hydra Torque BOPE bolts. Function Test BOPE. Noticed damage to top of annular element. Attempted to
perform shell test w/ no luck. Notified AOGCC Rep of situation. Started building second batch of new 6% KCL PHPA mud. Change out element on annular.
Quadco Rep arrived on location to bump test gas alarm system. R/U testing equip. Flooded & purged out air. Performed shell test w/ 4.5" test jt. 250 psi Low
2500 psi High for 5/5 min- Good test. Notified AOGCC Rep at 22:30 hrs. that we were ready to test. Cleaned rig floor and cellar area. Racked & tallied 46 jts of
4.5" DP. Cont. building new batch of mud. Dressed out shaker with screens. Crew change, held PTSM. AOGCC Rep arrived on location. Tested BOP's on 4.5"
test jt. as per AOGCC regulations. Quadco Rep bump tested gas alarm system. 5-1/2 hr. test time w/ 2 FP's. Test #3- TIW leaking, changed out valve and
retested same (Pass) Test #3- Valve #9 on CM leaking, attempted. to service, function, and retest w/ no luck. Changed out valve and retested same (Pass).
Drained stack, R/D testing equip. Currently B/D mud lines and choke manifold. Hauled 43 bbls solids to G&I. Cumulative Hauled = 578 bbls. Hauled 447 bbls
trash fluid to G&I. Cumulative Hauled =2092 bbls. Hauled 98 bbls Cmt to G&I. Cumulative Hauled = 98 bbls. Daily Downhole Losses = 13 bbls. Cumulative
Losses =13 bbls. Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/27/2023 Pull Test Plug and Install 9" ID wear ring. P/U and RIH with 46 jts. 4-1/2" 16.60# S-135 CDS40 drill Pipe T/ 1425'. PJSM, Hang off Blocks, Slip and Cut drill line
48'. Confirm Crown-O-Matic set and functioning properly. Flowcheck well, Static. POOH F/ 1425' standing back 4-1/2" 16.60# S-135 CDS40 drill pipe in derrick.
Top off wellbore with mud, R/U testing equipment for testing 7-5/8" Surface casing. Test T/ 3700psi for 30 charted minutes. Good Test. Pump 105.8 gallons and
bled back 105.8 gallons. Service Blocks, Top Drive, Iron Roughneck, Draworks, Gear Box, Drive Line, Floor Motor and Brake Linkage. Continue blowing down
choke, Complete loading and tallying 4-1/2" 16.60# S-135 CDS40 drill pipe to be singled in after BHA #3 6-3/4" Triple Combo Drilling Assembly. P/U 6-3/4"
Triple Combo BHA #3, P/U mud motor and adjust motor to 1.5 bend, M/U 6-3/4" Bit, DM, SP4, ALD, CTN, PWD, TM and download MWD, Shallow pulse test
Good. PJSM, Load Nukes and RIH with 4-1/2" S-135 CDS40 HWDP and Jars T/ 726'. RIH F/ 726' T/ 4156' picking up 4-1/2" 16.60# S-135 CDS40 drill pipe from
catwalk. Performed our make & break procedure on the last 25 jts of re-cut threads. Crew change, held PTSM. M/U TD, broke circ. Washed/reamed down
F/4156'-T/4180', started drilling soft cmt @ 4180'. Tagged plugs/FC @ 4210'. Drilled out shoe track and 20' of new formation T/4317'. P/U-81K S/O-57K ROT-
74K GPM-200 SPP-1380 psi WOB-7K TQ-6.5K Diff-250 psi ECD-10.42 ppg. CBU, displaced well over to 9.0 ppg 6% KCL PHPA mud. Circ. additional BU to
warm & condition mud. R/U testing equip. Flooded mud lines, choke manifold and purged out air. Perform FIT to EMW of 12.8 ppg = 671 psi. Pumped in 20.7
gals and bled back 20.7 gals. R/D testing and blew down same. Distance to well plan: 17.01' 5.38' High 16.14' Left. Hauled 0 bbls solids to G&I. Cumulative
Hauled = 578 bbls. Hauled 0 bbls trash fluid to G&I. Cumulative Hauled =2092 bbls. Hauled 0 bbls Cmt to G&I. Cumulative Hauled = 98 bbls. Daily Downhole
Losses = 13 bbls. Cumulative Losses =13 bbls. Daily Metal Recovered = 0 lbs. Cumulative Metal Recovered = 0 bbls.
3/28/2023 Continue Drilling/ Sliding as needed 6-3/4" Production hole F/ 4317' T/ 4624' MD GPM 250, SPP 1550psi, RPM 50, TQ 7K, WOB 9K, ECD 10.0ppg, Max gas at
240 units. MW in 9.0 MW out 9.0 P/U 112K, S/O 61K, ROT 77K Backreaming and Mad Passing slides as needed. Obtained SPRs @ 4374' MD 3455' TVD, MP
#! SPM 47 PSI 472/ MP #2 SPM 46 PSI 468. Continue Drilling/ Sliding as needed 6-3/4" Production hole F/ 4624' T/ 4870' MD GPM 265, SPP 1702psi, RPM
70, TQ 8.1K, WOB 7-12K, ECD 10.25ppg, Max gas at 280 units. MW in 9.05 MW out 9.05 P/U 120K, S/O 63K, ROT 80K. Backreaming and Mad Passing slides
as needed. Continue Drilling 6 3/4'' hole section sliding as needed f/ 4870' t/ 5244' 265 gpm 1700 psi SPP 70 rpm 8.7k tq on bottom, 8k WOB, Max Gas 195
Units, PUW 125k SOW 65k ROT 85k. Continue Drilling 6 3/4'' hole Section f/ 5244' t/ 5367' 265 gpm 1720 psi 70 rpm 9.5k tq on bottom, WOB 5k, Max gas 515
units, PUW 133k SOW 65k ROT 87k. CBU, Obtain SPR's and Survey, Flow check well static. Make wiper trip f/ 5367' t/ 4257' saw some 15k drag in a few spots.
Service rig and top drive, grease blocks and crown. RIH f/ 4257' t/ 5367' wash last stand to bottom no hole issues or fill on bottom, Pump Hi Vis Sweep around.
Drill Ahead 6 3/4'' Production section f/ 5367' t/ 5420' 253 gpm 1450 psi 70 RPM 9500 k tq on bottom, 133k PUW 67K SOW 91k ROT Wiper trip gas 939 units
Distance f/ plan 3.33' .1' High 3.33' Left. Hauled: 76 bbls Solids to KGF G&I. Cumulative: 654 bbls. Hauled: 409 bbls Fluid to KGF G&I. Cumulative: 2,501 bbls.
Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 0. Cumulative: 13 bbl. Daily Metal: 0 lbs. Cumulative: 0 lbs.
3/29/2023 Continue Drilling 6-3/4" Production section F/ 5420' T/ 5804' MD GPM 250, SPP 1740psi, RPM 70, TQ 10.4K, WOB 6K, ECD 10.47ppg, Max gas at 275 units.
MW in 9.0 MW out 9.05 P/U 141K, S/O 70K, ROT 93K. Continue Drilling 6-3/4" Production section F/ 5804' T/ 6361' MD GPM 250, SPP 1721psi, RPM 70, TQ
10-11K, WOB 6-8K, ECD 10.47ppg, Max gas at 332 units. MW in 9.0 MW out 9.05 P/U 158K, S/O 75K, ROT 100K, SPRs @ 5866' MD 4838' TVD MP#1 46 stks
594 psi, MP#2 46 stks 587 psi. Circulate bottoms up, obtain survey and SPR's, flow check well static. POOH f/ 6361' t/ 5307' with no issues. Rig service, grease
blocks and top drive, clean suction and discharge screens 90% packed off, grease and inspect draw works. RIH f/ 5307' t/ 6361' with no issues wash last stand
to bottom no fill, pump hi Vis Sweep. Drill Ahead 6 3/4'' Hole Section f/ 6361' t/ 6436' 250 gpm 1750 psi 70 rpm 11.8k tq on bottom 9k WOB. Drill Ahead f/ 6436'
t/ 6661' 250 / 215 gpm 1800-1550 psi 70 rpm 12k tq on bottom 10k WOB, 164k PUW 79k SOW 107k ROT Encountered loss zone @ 6460' taking 90-70 bph
loss rate while pumping, pumped 2 40 lb per bbl LCM pills no real change in loss rate, increase background LCM t/ 20 ppb. Spot 20 bbl LCM Pill 40 lb/bbl
outside the Bit. POOH f/ 6661' t/ 5688' Pulling to shoe to build more mud volume lost 330 bbls for the tour. Hauled: 60 bbls Solids to KGF G&I. Cumulative: 714
bbls. Hauled: 150 bbls Fluid to KGF G&I. Cumulative: 2,651 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 0. Cumulative:
13 bbl. Daily Metal: 0 lbs. Cumulative: 0 lbs.
3/30/2023 Cont. POOH F/ 5688' T/ 4249' inside 7-5/8" Casing to build mud volume. P/U 175K S/O 76K. Install FOSV into Drill Pipe. Calculated hole fill 16.56 BBLs, Actual
hole fill 18.94 BBL Gain. 2.3 BBL gain for trip. Wipe through tight spots during trip. Build 600 BBLs 9.0ppg KCL PHPA mud volume in Pits 4, 5, 6, 9 and 10.
Monitor Well on trip tank showing no gains or losses during entire time of building new mud. Pressure test back up FOSV, Perform Crown, Top Drive and
Draworks inspections. RIH F/ 4249' T/ 6652' washing last stand down with no set downs during entire trip. P/U 170K S/O 82K. Fill pipe and pump 22 BBLs of 40
ppb LCM pill and circulate at 150 GPM with 985psi SPP. and at BU Max Gas at 2832 units. Seen 40ppb LCM pill at bottoms up that was left in hole during trip
out. Continued pumping until second pill was out of bit. Continue Drilling 6-3/4" Production section F/ 6652' T/ 6914' MD GPM 224=247, SPP 1721-1800psi,
RPM 60, TQ 10-13K, WOB 6-8K, ECD 10.16ppg, Max gas at 2832 units. MW in 9.2 MW out 9.2 P/U 175K, S/O 83K, ROT 114K, SPRs @ 6853' MD 5803' TVD
MP#1 46 stks 630 psi, MP#2 46 stks 616 psi. Losses are 70 BPH. Continue Drilling 6 3/4'' Hole Section f/ 6914' t/ 7277' 245 gpm 1574 psi 60 rpm 13.6k tq on
bottom, 6-8k WOB, PUW 190k SOW 85k ROT 114k, Max gas 192 units, MW 9.15 ppg ECD 10.19 ppg, Loss rate Slowing f/ 70 bph t/ 30 bph, flowing back on
connections. Continue Drilling 6 3/4'' Hole Section f/ 7277' t/ 7533' 245 gpm 1610 psi 60 RPM 14.2k tq on bottom 6-8k WOB, PUW 195k SOW 85k ROT 117k,
Max Gas 448 Units MW 9.1 ppg ECD 10.07 ppg, 20 bph while pumping, flowing back on connection. Hauled: 17 bbls Solids to KGF G&I. Cumulative: 731 bbls.
Hauled: 143 bbls Fluid to KGF G&I. Cumulative: 2,794 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 1,013. Cumulative:
1,026 bbl. Daily Metal: 0 lbs. Cumulative: 0 lbs.
3/31/2023 Continue Drilling 6-3/4" Production section F/ 7533' T/ 7786' MD GPM 250, SPP 1610psi, RPM 60, TQ 14K, WOB 5K, ECD 10.09ppg, Max gas at 463 units.
MW in 9.1 MW out 9.1 P/U 208K, S/O 93K, ROT 120K, SPRs @ 7600' MD 6531' TVD MP#1 46 stks 630 psi, MP#2 50 stks 655 psi. Pump 20 BBL Hi-Vis sweep
at 7658' MD came back 20 BBLs late with 10% increase in cuttings, Continue to weigh up mud to 9.3ppg. Continue Drilling 6-3/4" Production section F/ 7533' T/
7786' MD GPM 250, SPP 1610psi, RPM 60, TQ 14K, WOB 5K, ECD 10.09ppg, Max gas at 463 units. MW in 9.1 MW out 9.1 P/U 208K, S/O 93K, ROT 120K.
Monitor well and observe deflate of charged up formation after Pumps off. 10 BBL returned at 1 min. 20 BBL return at 2 min. 30 BBL return at 3 min. 35BBLs
return at 5-1/2 min. 40 BBLs return at 5-1/2 min. Continue fading out w/ 115 BBLs returned at 48 min. Moved drill string every 5 min. POOH F/ 7906' T/ 6670'
P/U 205K S/O 90K with no overpulls observed. P/U Calculated Hole Fill 6.9 BBLs Actual Hole Fill 24.2 BBLs. 17.3 BBLs returned from formation. Rig Service,
Grease Crown, Blocks, Top Drive, Iron Roughneck and Gear Box. Inspect Draworks and Brake Linkage. RIH F/ 6670' T/ 7906' P/U 205K S/O 90K washing last
stand down with no set downs and no fill. Calculated Displacement 23.1 BBLs Actual Displacement 20.0 BBLs. Pump Hi-Vis sweep Max Gas 1887 units at BU.
Continue Drilling 6-3/4" Production section F/ 7906' T/ 8248' MD GPM 250, SPP 1610psi, RPM 60, TQ 14K, WOB 5K, ECD 10.09ppg, Max gas at 1887 units.
MW in 9.3 MW out 9.3 P/U 200K, S/O 95K, ROT 127K. Hi-Vis Sweep came back 11 BBLs late with no increase. Continue Drilling 6 3/4'' production Section f/
8248' t/ 8560' 250 gpm 1620 psi SPP 60 RPM 17.3k tq on bottom, WOB 8k MW 9.3 ppg ECD 10.06 ppg, Max Gas 432 PUW 205k SOW 95k ROT 127k
Distance f/ plan 8.31' .07' Low 8.31' Left. Hauled: 61 bbls Solids to KGF G&I. Cumulative: 792 bbls. Hauled: 214 bbls Fluid to KGF G&I. Cumulative: 3,008 bbls.
Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 331 bbls. Cumulative: 1,357 bbls. Daily Metal: 0 lbs. Cumulative: 0 lbs.
4/1/2023 Continue Drilling 6-3/4" Production section F/ 8560' T/ 8898' MD GPM 248, SPP 1800psi, RPM 60, TQ 17.1K, WOB 3-10K, ECD 10.10ppg, Max gas at 611
units. MW in 9.3 MW out 9.3 P/U 225K, S/O 103K, ROT 143K. Pump 20 BBL Hi-Vis sweep @ 8600' MD came back 15 bbls late with 15% increase. SPRs at
8898' MD 7800' TVD with 9.3ppg MW. MP #1 46 stks 681psi MP #2 46 stks 687psi. Bleed off 101 BBLs in 55 minutes working pipe and standing back two
stands while bleeding. Bled down to a rate of .75 BBL per minute. Bleed back was 1/2 of what was previously recorded. 1min 5 BBLS total, 2 min. 9-1/2 BBLs
total, 3 min 14-1/2 BBLs total, 4 min 19-1/2 BBLs total, 5 min 22-1/2 BBLs. POOH F/ 8774' T/ 7906' with no issues. P/U 240K Calculated Hole Fill: 6.4 BBLs,
Actual Hole Fill: 21.5 BBLs, Total of 145 BBLs exhausted from T18 Coal/ Sandstone formation at 6460' MD. Grease Crown, Blocks, Top Drive, Draworks and
Iron Roughneck. Set Torque on Top Drive T/ 18K. RIH F/ 7906' T/ 8898' washing last stand down with no issues or fill. Pump 20 BBLs Hi-Vis sweep and
observed 2064 units at bottoms up. Continue Drilling 6-3/4" Production section F/ 8898' T/ 9147' MD GPM 248, SPP 1587psi, RPM 60, TQ 17.1K, WOB 3-10K,
ECD 10.10ppg, Max gas at 2064 units. MW in 9.3 MW out 9.3 P/U 225K, S/O 103K, ROT 143K. Pump 20 BBL Hi-Vis sweep @ 8898' MD came back 15 bbls
late with 15% increase. Continue Drilling 6 3/4'' Production Section f/ 9147' t/ 9423' 250 gpm 1775 psi SPP 50 RPM 17.8k tq on bottom, 3-10k WOB MW 9.4 ppg
ECD 10.16 ppg PUW 245k SOW 100k ROT 145k, Distance to Plan 20.47' 20.35' Low 2.02' Left. Hauled: 51 bbls Solids to KGF G&I. Cumulative: 843 bbls.
Hauled: 159 bbls Fluid to KGF G&I. Cumulative: 3,167 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 198 bbls. Cumulative:
1,555 bbls. Daily Metal: 0 lbs. Cumulative: 0 lbs.
4/2/2023 Continue Drilling 6-3/4" Production section F/ 9423' T/ 9706' MD GPM 250, SPP 1825psi, RPM 50, TQ 19.5K, WOB 8K, ECD 10.20ppg, Max gas at 258 units.
MW in 9.35 MW out 9.3 P/U 245K, S/O 108K, ROT 152K. Pump 20 BBL Hi-Vis sweep @ 9515' MD came back on time with 50% increase. SPRs at 9456' MD
8345' TVD with 9.35 MW MP #1 SPM 46 PSI 655 MP #2 SPM 46 PSI 645. Continue Drilling 6-3/4" Production section F/ 9765' T/ 9897' MD GPM 252, SPP
1841psi, RPM 70, TQ 19.8K, WOB 6-10K, ECD 10.23ppg, Max gas at 334 units. MW in 9.4 MW out 9.35 P/U 250K, S/O 115K, ROT 155K. Pump 20 BBL Hi-Vis
sweep @ 9765' MD came back 6 BBLs late with no. increase in cuttings. Increased RPM T/ 75 and pump rate T/ 300 GPM after sweep was out of the bit and
unloaded hole with consistent cuttings. Increase Lubes in mud F/ 2% T/ 3% starting at 9765'. Continue Drilling 6 3/4'' Production Section f/ 9897' t/ 10012' 248
gpm 1837 psi 50 rpm 19.8k tq on bottom WOB 10k 9.4 ppg MW ECD 10.10 ppg, 250k PUW 110k SOW 152k ROT. CBU spot LCM Pill. Monitor well bleed back
fluid 130 bbls in 1 hour rate slowing to 11 bph. POOH on elevators f/ 10012' t/ 8962' No Hole issues. Monitor well on trip tank @ 8962' Initial flow rate 8.64 bph
after 90 min 3.54 bph. POOH f/ 8962' t/ 7668' Monitor well f/ 15 min on trip tank well static no flow. POOH f/ 7668' t/ 4253' No hole issues. Hauled: 45 bbls Solids
to KGF G&I. Cumulative: 888 bbls. Hauled: 165 bbls Fluid to KGF G&I. Cumulative: 3,332 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid
Lost Down Hole: 287 bbls. Cumulative: 1,842 bbls. Daily Metal: 0 lbs. Cumulative: 0 lbs.
4/3/2023 Service Blocks, Top Drive, Iron Roughneck, Draworks, Gear Box, Drive Line, Floor Motor and Brake Linkage while well on trip tank with No Gains or Losses.
Slip and Cut 22 wraps (105') of drill line. Reset and test Crown-O-Matic, Good. While monitoring well on trip tank with No Gains or Losses. Replace Clutch/
Eaton valve on drillers console while monitoring well on trip tank with no gains or losses. RIH with 6-3/4" BHA #3 F/ 4253 T/ 7535' Calculated displacement: 73.2
BBLs Actual displacement 10.4 BBLs Losses to well: 62.8 BBLs. Trouble getting past T18 formation into mother well bore. 15K setdown at 6445' MD. Align
directional tools to high side and drilled through obstruction to get into. Mother Bore with assistance of directional driller. 15K set down at 6482' wiped through
and clear before continuing on T/ 7535'. Fill pipe and circulate to condition mud before going to 10,012' MD. GPM 151, SPP 935, RPM 70, TQ 13-15K. Returns
was puddled up 9.8ppg with vis of 148 and 57 YP. Overboarded returns (130 BBLs) until 9.4ppg KCL PHPA mud showed up. M/U another stand so as not to
wash out section T/ 7600' MD. Max Gas 2988 units, Continue circulating while building 300 BBLs of 9.4ppg KCL PHPA mud. Lost 227 BBLs T/ T18 formation.
Shut off pumps and allow well to exhale. Bled back 53 BBLs in 50 minutes. RIH F/ 7600' T/ 10012' washing last stand down. Trip Displacement Calculated: 47.5
BBLs Actual Displacement: 52.3 BBLs Difference: +4.8 BBLs. Circulate bottoms up Max gas 2476 units on bottoms up, Pump Hi Vis Sweep around sweep back
100 stks early 25% increase in cuttings. Monitor well and bled back 33 bbls in 50 min initial flow rate 144 bph slowed t/ 4 bph. POOH f/ 10012' t/ 7242' No Hole
Issues. Monitor well on trip tank initial flow rate 3.3 bph slowing t/ 1.1 bph in 30 min. POOH f/ 7242' t/ 4245' No hole issues, Dropped 2.41 drift on stand #70 of
DP. Monitor Well on trip tank Initial Flow Rate of 1.44 bph ( Service rig and top drive while monitoring well) total pit gain 2.5 bbls pit strap 3 bbls pason. Hauled:
19 bbls Solids to KGF G&I. Cumulative: 907 bbls. Hauled: 136 bbls Fluid to KGF G&I. Cumulative: 3,468 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative:
98 bbl. Fluid Lost Down Hole: 201 bbls. Cumulative: 2,043 bbls. Daily Metal: 0 lbs. Cumulative: 0 lbs.
4/4/2023 Cont to monitor flow with bit parked at 4245 (inside casing shoe). Flow rate dropped from 1.4 bph to .9 bph over 6 hrs. Total gain over 6 hrs = 6 bbls. Discussed
plan forward with Drilling Engineer, decision made to TIH to bottom, increase MW to 9.5ppg then pump OOH. TIH from 4245' filling pipe every 17 stands (1000').
TIH at 50/fpm. Pipe displacement varied anywhere from 2.9 to 6.9 bbls per 5 stands (normally 6.1 bbls per 5 stands). started increasing surface volume MW to
9.5 ppg during trip. No issue at 6460' (ledge). Stopped at 7925', filled pipe for CBU. CBU at 174 gpm-925 psi. 33 rpm-7500 ft/lbs off bott torque. Gas climbed
over 25 minutes to a max of 2618 units, then dropped off to 600 units over another 20 minutes. Cuttings appeared to be oil wet barite on shakers, with more
coarse sand and small chips of coal at bottoms up. Cont TIH on elevators from 7925' to 9954' with no issue, filled pipe every 17 stands. At 9954' MU topdrive,
filled pipe, washed and reamed to bottom. For entire trip, calc hole fill = 103.7 bbls, actual hole fill = 79.1 bbls (24.6 bbls under). CBU staging from 174 gpm up
to 194 gpm-1083 psi, 60 rpm-16,000 to19,544 ft/lbs off bottom torque. Had a max of 1702 units gas that dropped off to 1143 units, then climbed again to 1348
units before dropping to 20 units. Cont condition mud to 9.5 ppg. Lost total of 36.29 bbls over 2 hrs circ. Obtained SPR's with new mud weight of 9.5 ppg, shut
down and monitored well for flow. Initial rate at 7.1 bph after 30 min slowed t/ 3 bph rate. POOH w/ pumps 112 gpm 520 psi f/ 10012' t/ 6410' no hole issues,
30.8 bbls total displacement 7.1 bbls over displaced for trip. Hauled: 4 bbls Solids to KGF G&I. Cumulative: 911 bbls. Hauled: 76 bbls Fluid to KGF G&I.
Cumulative: 3,544 bbls. Hauled: 0 bbl Cement to KGF G&I. Cumulative: 98 bbl. Fluid Lost Down Hole: 30 bbls. Cumulative: 2,073 bbls. Daily Metal: 0 lbs.
Cumulative: 0 lbs.
4/5/2023 Cont to pump OOH from 6410 to 4248 at 112 gpm-530 psi, pulling 28 ft/min, no rotation, up wt 155K. Parked string just inside surface casing. Calculated
displacement = 18.4 bbls, actual displacement = 22.9 bbls. Monitored well for flow at flow line/shakers. Initial rate at .15 bph that dropped to .02 bph over an
hour. Cont POOH on elevators at 35 to 45 ft/min to HWDP at 726. Calculated hole fill = 23 bbls, actual hole fill = 24.6 bbls. *Pulling any faster than 45 ft/min
seemed to induce swabbing and hole fill would be off per 5 stands. Monitored well on trip tank, hung blocks, cut and slipped 55' drill line. Hole took .45 bbls over
one hour. Calibrated hook load. Cont POOH LD HWDP, jars and NM flex DC's. Removed sources, Download MWD, L/D Remaining BHA Broke bit graded 2-2 in
gauge, L/D all BHA component f/ rig floor, Clean and clear rig floor. R/U Parker TRS equipment, Load racks and bring centralizers to floor. PJSM. RIH w/ 4.5''
Float equipment baker locking jts, Check floats (good) Continue RIH w/ 4.5'' 12.6# DWC Liner t/ 4052' at slower speed to keep from pushing mud away,
installing centralizers as per detail.
4/6/2023 Cont PU single in hole with 4 1/2" DWC/C-HT 12.6# L-80 liner from 4052' to 4259 at 20-25 ft/min getting decent displacement. Top filling on the fly, topping off
every 10 jnts. MU XO and topdrive, CBU at 112 gpm-148 psi. Minimal losses. Cont PU single in open hole with 4 1/2" liner from 4259' to 5919' getting good
displacement at 20 ft/min. C/O elevators, PU and MU Baker HRD-E ZXP Flex Lock V production liner hanger assembly w/5.75" SBR, mixed and poured xanplex,
MU XO and 1st stand 4 1/2" drill pipe. Eased in hole to 6020'. MU topdrive, CBU at 120 gpm-219 psi, max gas of 81 units at bottoms up, lost 11 bbls during circ,
blew down topdrive, up wt 80K, dwn wt 60K, did not attempt to obtain any rotating parameters. Cont ease in hole at 20 ft/min on stands from 6020' to 8000' top
filling on the fly, topping off every 10 jnts. At 6465' to 6468' we set down 5K up to 10K then broke through with no further issues. Any faster than 20 ft/min we
were pushing away mud. At 8000' MU topdrive and circ at 125 gpm-283 psi for 52 bbls. Lost 5 bbls during circ. Shut down, blew down, called out cementers.
Cont ease in hole at 20 ft/min from 8000' to 10012',set down @ 9684' worked through 10k set downs, set down @ 9932' unable to get past, Wash down
remaining stand to bottom. Circulate and condition mud 112 gpm 435 psi. Blow down top drive, R/U cementers and cement head, PJSM. Halliburton pumped 3
bbls water to flush lines, then 5 bbls to fill lines. Shut in at Baker cement head and PT lines at 536 psi low 4744 psi high. Lined up Baker cement head to
Halliburton, pumped 30 bbls 10.5 ppg spacer at 30 bpm 550 psi, followed with 194 bbls (455 sx) 12 ppg Type I II Lead. cement at 4 bpm, 425 to 80 psi, followed
with 22 bbls (98 sx) 15.3 ppg Type I II Tail cement at 3 bpm- 78 psi. Baker released dart, Halliburton then displaced with 9.5 ppg 6% KCL mud at 4 bpm- 50 to
160 psi. 52 bbls into displacement saw dart latch wiper plug. With 20 bbls to go, reduced rate to 2. bpm- 872 psi and bumped plug/landing collar 144 bbls into
displacement (calculated at 144.8 bbls). FCP 1115 psi. Halliburton increased to and held 2230 psi for 1 minute. Slacked off on blocks, anchor holding. Increased
pressure to 3330 psi and held 5 minutes. Slacked off on blocks from 200 K to 15K,. CIP at 23:42 on 4-6-23. 76 BBL loss throughout the job. Increased pressure
to 4500 psi and held 1 minute to shift HRD-E and release run tool. Saw slight bobble on weight indicator. Bled back 1.5 bbls to truck and floats held. PU weight
82 K, run tool released. RD cement hose, LD Baker cement head. MU topdrive. PU 6 to clear dogs from hanger top, slacked off from 80 K to 25 K on liner top
and saw a good indication on weight indicator, dog sub sheared, Pressured up to 635 psi on drill string and PU slowly. Once psi started dropping, rig started
pumping and did one full circ at 455 gpm-720 psi. Had trace of spacer to surface no cement. RD and released Halliburton crew. Clear floor Blow Down top drive.
POOH f/ 4021' t/ Surface, Break down running tools, dog sub sheared, L/D Same. Break down cement head and pup joints, break out crossovers, Flush stack
with black water.
4/7/2023 MU Baker polish mill, XO and single joint, C/O camp gen set. Troubleshoot Pason, service rig, cont pit cleaning and centrifuge mud down to 9.0 ppg. TIH on
stands from 53' to 4012'. Up wt 75K, dwn wt 62K. Eased down and tagged top of liner at 4956' with current BHA. PU and start pumping 112 gpm-164 psi, 27 rpm-
3500 ft/lbs off bott torque. Eased down and dressed liner top as per Baker. Park polish mill no-go 1' off seat and stopped rotating, pumped hi-vis spacer with
both pumps followed with inhibited fresh water to displace upper portion of well. Once IFW rounded the corner PU out of SBR and displaced at 277 gpm-337 psi.
With water to surface shut down. Monitored well for flow (no flow) while cleaning under shakers and flow troughs in pits. POOH LD 4 1/2" DP from 4040 to
surface, LD XO and Baker polish mill. Closed blinds, opened kill and choke HCR's, RU test hose and chart recorder, purged air, pumped 3.45 bbls to achieve
3500 psi on casing/liner lap. Held 30 min on chart, good test, bled back 3.1 bbls. RD test equipment. MU mule shoe and TIH on stands from surface to 3687'
POOH L/D DP, RIH w/ Remaining DP f/ Derrick t/ 1550' POOH L/D Remaining DP, L/D Mule Shoe, Clear Floor. Pull Wear Ring R/U TRS Equipment, held
PJSM. RIH w/ 4.5'' 12.6# L-80 Tie Back Assembly f/ Surface t/ 717'.
4/8/2023 Cont PU single in hole with 4 1/2" 12.6# L-80 DWC/C-HT tieback tubing from 717' to 2534'. MU VANOIL chemical injection mandrel sn:23634-01, RU Pollard
sheave and control line to mandrel. Tested control line at 2000 psi for 10 minutes then bled to 1000 psi for tripping in hole. Good test. Held PJSM on trip in with
control line and banding same. Cont PU single in hole from 2545' to 3892'. MU Baker Hughes Onyx 5000 psi SSSV valve with 3.870" ID. Stage second spool of
control line on rig floor, attach to SSSV and test control line at 2000 psi, good test. Cont PU single in hole from 3949' to 4027', PU one extra joint, ease down
and tag no on liner top. WEG at 4064', top of liner at 4054'. L/D top joint, MU XO and topdrive. Circulate and displace upper portion of well to 3% KCL brine at
184 gpm-53 psi. Broke off topdrive and XO, blew down topdrive. L/D top single, MU 10.24' space out pup, MU top single, MU landing joint and hanger, terminate
both control lines through hanger, RD casing tongs, drained BOP stack, S/O and landed hanger. Up wt 60K, dwn wt 50K, 35K on landed hanger. Installed total
83 SS bands, no-go 1.55' off seat. RILD's, RD Pollard control line and sheave, cleared rig floor, LD landing joint. RU test equipment for MIT's, flooded stack and
choke manifold, purged air, closed blinds. Pumped 1.8 bbls and pressured up on tubing to 3500 psi for 30 min on chart, bled back 1.9 bbls, swap hose and
pressure up down backside t/ 3500 psi f 30 min pumped in 1.64 bbl bled back 1.4, Set TWC. Flush mud lines and stack with baraclean soap pill. Open ram
doors and inspect rams and cavities, remove bails and elevators, Remove flow line and bell nipple, replace grabber cylinder on top drive, close ram doors and
tighten. Install trolly beam, N/D flow box, remove choke and kill lines, remove koomey lines, break bolts, Hoist stack off wellhead set to side ( Employee ran into
heater framework in cellar, cut on cheek, Sent to town for medical evaluation), rigged down third party shacks and moved away from rig. Bring in and prep dry
hole tree, install tree on B section, tighten bolts, Test Void t/ 5000 psi f/ 15 min, Clear floor of subs tongs and other equipment. Disconnect gen 3 and moved,
continue loading trailers and prep f/ move.
4/9/2023 Removed kelly hose and service loop, removed torque bushing, Wellhead Reps tested neck seals then tree at 5000 psi for 15 min each, good tests. Pulled two
way check and closed master valve. Secured topdrive to cradle, removed HandyBerm along back edge to allow CCI access to boiler skid,. CCI on location at
10am, staged crane and removed windwalls from pits, removed clam shell and centrifuge, bridled up for derrick scope down, cont PU load mats, staging
equipment at Pearl Pad and Kalotsa Pad. Rig Released at 12:00 on 4-9-23.
Activity Date Ops Summary
4/20/2023 Fox coil and cruz crane arrive at Susan Dionne pad. Hold TBT and approve PTW. Spot rain for rent tanks, crane and coil unit. RU hardline to Yellow jacket
triplex pump. Haul water to supply tank from Kalotsa pad. NU BOP's on tree. Test BOPE to 250 psi low / 3500 psi high. Good test. Jim Regg with AOGCC
waived witness via email at 11:50 on 4/19/23. Secure well with night cap on top of BOP's. SDFN.
4/21/2023 Fox Coil and Cruz meet at Susan Dionne and hold TBT, approve PTW. PU lubricator and load coil with water. Pull test CTC to 25K. MU DFCV's and disco and
PT to 3500 psi. MU remaining BHA with 2.87" wash nozzle. PT lubricator to 3500 psi,Pump open SSSV. Open well and RIH with 2.26" CTC, 2.13" DFCV, 2.13"
Disconnect (5/8" ball), 2.0" xo, 2.87" xo, 2.87" wash nozzle. Online with pump at 1.0 bpm when in liner at 4200'. CTP = 1700 psi. Tag PBTD at 9887' ctmd. Set
down jetting, no able to get any deeper. PU coil to get wt back at 9872'. Stop coil and increase rate to 1.5 bpm, CTP = 3550 psi. Getting black mud returns to
surface. Pump 50 bbls of water while on bottom with coil. POOH at 70 ft/min chasing mud returns to surface while pumping at 1.5 bpm. Once mud returns clear
up, increase POOH speed to 100 ft/min. Coil at surface. Break off nozzle and xo's. MU Halliburton memory cement bond log toolstring. Toolstring will turn ON at
16:30. Log up at 40 ft/min from 9860' to 4100' (50' above liner hanger). Stop for 5 minutes. POOH. Laydown logging toolstring, and lubricator. Secure well with
night cap on top of BOPs. Download data and determine Top of Cement = 5200' (uncorrected). SDFN.
4/22/2023 Fox coil and cruz crane arrive at Susan Dionne office. Hold TBT and approve PTW. Warm up equipment and pick up injector. MU lubricator and coil roll on
connector with stinger and 2-1/8" reverse out nozzle. Cool down N2 unit and PT hard line to 4000 psi. Set up to reverse circulate fluid from wellbore with
Nitrogen. On-line with N2 down coil backside at 800 scf/m and 1500'. Increase N2 rate to 1800 scf/m at ~ 7100'. RIH and stop coil at 9860' while pumping at
1800 scf/m. WHP = 3350 psi, CTP = 90 psi. Getting ~ 1 bpm returns to surface. Straight N2 returns to surface once all fluid recovered. Returned 153 bbls fluid
with expected of ~ 150 bbls. POOH with coil once all fluid is returned to surface. WHP = 2900 psi. Offline with N2 pump while POOH. Coil at surface. Trap ~
2400 psi on well. Bleed off pressure inside coil reel. Haul off fluid returns to G&I. RDMO coil.
4/27/2023 AK E-line arrive on location. Hold TBT and approve PTW. Pick up wireline valves and stab on top of tree. MU lubricator and 1-11/16" GPT toolstring. PT
lubricator to 250 psi low / 3500 psi high. Bleed tubing pressure down from 2300 psi to 1800 psi. RIH with 1-11/16" GPT toolstring. Find fluid level at 9812'
(corrected). POOH and laydown toolstring. MU and RIH with 2-3/4" x 20' perf gun. GR/CCL to top shot = 9.0'. Send correlation log to RE/GEO and confirm on
depth. Perforate T160 zone from 9484 - 9504'. Initial pressure = 1808 psi. 5 min = 1825 psi. 10 min = 1835 psi. 15 min = 1845 psi. All shots fired. Bull plug on
gun was damp. Attempt to flow well. Drop tubing pressure from 1845 psi to 1350 psi. No gas at surface. RIH with GPT. Find fluid level at 8150'. RIH and tag at
9864'. POOH and find fluid level is still rising, now at 7860'. Laydown GPT toolstring and lubricator. Secure well with night cap on top of wireline valves. SDFN.
5/18/2023 AKE-line and Fox Energy arrives on location obtains PTW and holds sim-op PJSM. Spots equipment. Confirm with production operator function of SSSV.
(Pressure up to 4800 psi),E-line RU tool string: weight bars, GPT/fluid sample catcher in lubricator. MU WLV & pump in sub on wellhead. PU and stab on. Fox
N2 MU hardline and tie into side wing valve. PT all with N2: 500 psi low / 4500 psi high. Pass,Open swab (SITP - 1928 psi ). RIH and locate FL at 6250'. PU to
6000' and standby to pump N2. Roll on pump at 1000 scfm and walk pressure up to 3500 psi (1.5 hrs.) SD pump. Run GPT pass and locate FL at 7450'. Roll on
pump at 1000 scfm and bring pressure up to 4000 psi. (45 min.). SD pump. Run GPT pass and locate FL at 8370'. Continue compressing fluid into T-160 perfs
(9484'-9504') and logging FL to depth of 9150'. POOH. Rig back and release Fox Energy crew. OOH w/ GPT. Recover and bottle fluid sample. MU Gun Gamma
Ray/CCL and 3.50" CIBP. (15.4' CCL to top of plug). Open swab (4000 psi). RIH, correlate and send log to Geo. Confirmed on depth and set plug at 9459'. (25'
above- T-160 perfs). 3400 psi when set. POOH. OOH. Bleed tubing down to 3000 psi. MU 3.50" x 13' dump bailer, fill with 6.3 gal. cement. RIH and dump
cement on plug. POOH. OOH. LD bailer tools, riser and add night cap on pump 'n' sub on well head. Secure well. Leave location. Total N2 pumped - 232,399
scf.
5/19/2023 AKE-line arrive on location, obtain PTW and hold PJSM. Discuss with production, wellhead access requires need for manlift. Start equipment and relocate
various support equipment. Well static with CIBP/cement in place and 2942 psi N2. Rehead rope socket. MU 2-3/4" x 15' perforating gun (6spf/60D). (13.9' CCL
to top shot). Bleed well down from 2942 psi to 2500 psi. PU tools and lubricator and stab on well. Manlift arrives. Open swab and RIH. Continue to bleed well
down to 2200 psi. Run correlation pass, send to Geo and confirm on depth. Position gun and shoot interval 8930'-8945' (T-145). Initial: 2206.8 psi. 5 min: 2209
psi. 10 min: 2206.3 psi. 15 min: 2204.2 psi. OOH. 2198.7 psi. LD spent gun, all shots fired. Bull plug dry. MU GPT w/ fluid sample tool. Open swab and RIH w/
GPT and fluid sample collector. Stop at 9430', (500' below perforations) no fluid detected. PU to 8700'. Open wing and begin flow back to trip tank. Draw down to
1600 psi and rerun GPT pass. No fluid or LEL's detected. Draw down to 1000 psi. RIH w/ GPT, no fluid or LEL's detected. Draw down to 71 psi. RIH w/ GPT, no
fluid or LEL's detected. Orders to P&A zone. POOH. MU CIBP. (14.5' CCL to top of plug. PU 3.50" OD CIBP and RIH. Tie-in using previous "on depth" perf
correlation. Set plug at 8905' (25' above perfs) and POOH. MU 3.50" x 13' cement dump bailer. Mix and fill bailer with 6.3 gal. cement and RIH. Set on plug and
dump cement (Est. TOC - 8895'). POOH. OOH. LD tools and lubricator. Night cap and secure well. SD for weekend. Inform production of well status and leave
location.
5/22/2023 Travel to Susan Dionne. PJSM and permits with Fox Energy N2. Travel to Paxton and start equipment and rig up Fox Energy N2. Pressure test lines to 3500
PSI. Test good. Start pumping N2 down well at 800 scfm rate. AK E-Line arrives on location. Increase N2 rate to 1000 scfm. Reached target PSI of 1600. N2
total scf 140,539 at 1659 gallons. S/D Fox N2. Rig up AK E-Line. Pressure test AK E-Line to 3500PSI. Test good. Run in hole with 20' x 2-3/4" carrier gun. Tag
existing CIBP / Cement at 8905'. Pick up hole and tie in to T-140 zone at 8694' to 8714'. CCL to TS = 8.9' making target CCL depth 8685.1' to place top shot at
8694'. Send tie in log to town for approval. Log approved. Spot 20' x 2-3/4" gun across T-140 zone with TS at 8694'. Fire gun. POOH. Start PSI 1599 / 5 Min
1638 / 10 Min 1674 / 15 Min 1707 / 20 Min 1750 / 25 Min 1778 / 30 Min 1812. OOH. Lay down gun. All shots fired. End cap dry. Make up GPT tool and sample
bailer. Run in hole with GPT tools and sample bailer. Made logging pass. Found top of fluid at 8820' below perfs. Logged up above new T-140 perfs and saw
cooling at perfs. Unit stand by. Send log to town. Directed to POOH. Out of hole. Found dirty water in sample bailer. Sample turned over to Lead Operator. Line
up to bleed N2 off well through tank. Pad Op started to bleed of N2. Start PSI 2600. Fox N2 and AK E-Line secured equipment. Production to continue bleeding
off N2 then will go to production once they have gas. Fox & AK E-Line will return in morning to either RDMO or continue with job if production over night is not
successful. Close out permits. Return to shop.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
NINU Paxton 12
Ninilchik
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00047 Paxton 12 Completion
Spud Date:
5/23/2023 Travel to Susan Dionne. Engineers want to let this well flow test for some time before additional work to be done to well. Travel to location. Service equipment
and work on tools. Return to base.
6/7/2023 Travel to Susan Dionne. PJSM and permit. Travel to Paxton pad. R/U AK E-Line. PT Lubricator to 3500psi. Arm 14' x 2-3/4" Gun FOUR for T-120 zone at 8626'
to 8640' CCL to TS = 9',RIH w/ Gun FOUR. Made correlation pass at T-120 zone. Sent to town for approval. Town adjusted by 2'. Made adjustment. Re-send
revised log to town. Town approved. Position Gun FOUR at T-120 zone 8626' to 8640'. CCL to TS = 9'. CCL depth will be 8617' for TS to be at 8626'. Fire gun.
POOH. Start PSI 81 / 5 Min 344 / 10 Min 890 / 15 Min 1280 / 20 Min 1620 / 25 Min 1890 / 30 Min 2065. OOH. Bleed off lubricator. Lay down gun. All shots fired.
RDMO AK E-Line. Plan forward: Perforating on Pearl 11 tomorrow morning contingent on CT finishing up today.
6/11/2023 PTW, JSA. MIRU Fox energy CTU 8 with 1.75" coil to clean out hydrate plug. 24 hr. BOPE test witness notification sent. No inspector witness. Test BOPE
250/3500 psi. Good test. Supply and return tanks spotted in containment. Load supply tank with 5200 gallons of methanol. Operator pumped 2 bbls methanol
down tubing, broke through hydrate plug. Brought well online. Rig down coil tubing.
6/28/2023 Travel from YJ shop to Susan Dionne pad. PJSM & permit. Travel to Paxton pad. Spot equipment on Paxton 12. MIRU YJ E-Line. PT surface equipment 500 /
3500 PSI. Test good. Well flowing at 207 PSI. SI wing. Open swab & RIH w/ 20' x 3.00" bailer as a drift to 8700'. No issues w/ drift run. POOH. OOH. Lay down
bailer & pick up Gun ONE. RIH w/ 20' x 2-7/8" carrier Gun ONE. Target depth 8645' to 8665' in T-120 zone. CCL to TS = 9.5'. CCL depth will be 8635.5' to place
TS at 8645'. Made tie in pass. Sent log to town for approval. Town approved. Well has been on steady pressure build up since shut in. Position Gun ONE and
fire. POOH. Start PSI 1580 / 5 Min 1595 / 10 Min 1603 / 15 Min 1608 / 20 Min 1615 / 25 Min 1620 / 30 Min 1625. OOH. Lay down Gun ONE. All shots fired. Pick
up Gun TWO. RIH w/ 20' x 2-7/8" carrier Gun TWO. Target depth 8625' to 8645' in T-120 zone. CCL to TS = 9.5'. CCL depth will be 8615.5' to place TS at 8625'.
Made tie in pass. Sent log to town for approval. Town approved. Position Gun TWO and fire. POOH. Start PSI 1717 / 5 Min 1725 / 10 Min 1729 / 15 Min 1732 /
20 Min 1737 / 25 Min 1741 / 30 Min 1744. OOH. Lay down Gun ONE. All shots fired. RDMO YJ E-Line, Well turned over to production. YJ crew travel back to
base.
7/23/2023 Evaluating for additional perforations, flowrate declining rapidly.
8/12/2023 PTW, PJSM, R/D coil off KTU 43-06XRD2, loaded eq. cleaned tanks & Moved to Paxton 12,Spotted Eq. R/U Circ lines,,Fill surface eq. test BOPE 250/3500 as
per Hilcorp & AOGCC requirements, witness was waived by AOGCC inspector Jim Regg, continue RIgging up, secure well, SDFN.
8/13/2023 PTW, PJSM, warm Eq,P/U injector & lubricator, M/U coil connector, Pull test 25k, good, Cont. M/U BHA- 1.75 coil connector, CK valve, jars, disconnect, circ
sub, PT coil t/3500psi good,,P/U 2 7/8 mud mtr, 3.5" mill. =25.11' total BHA. stab on well, surface test Motor, good, PT 250/3500psi, good,RIH t/tag @ 8870,
CTM, Fill hole, 70 bbls,,Wash down t/8892', mill CMT down t/tag plug @8903' CTM,,Mill CIBP, 2.2bpm, 2300psi tq off, 2700-2800psi tq on, 1-4k WOB, did lose
tq temporally, worked through that, cont. milling till plug started moving. Chase plug down t/9454' CTM,,CBU, POOH,OOH, shut in well, pull injector, install night
cap,WHP -0, IA 200, OA 80, L/D BHA, & lubricator, rack back injector. SDFN.
8/14/2023 AK E-line rigs down from Pearl 8, travels to Paxton. Obtains PTW & PJSM. Spot equipment and RU. MU GR/CCL and 3.80" GR. Move to well and PT 250/2500
psi. Pass. RIH, make several passes through T-120 and T-140 perforations (8600'-8800'). Run correlation pass to confirm on depth. Run through milled plug
location (8905') and T-145 perfs at 8930'-8945'. POOH. SLB spotted N2 transport and pump. MU 3.80" x 26.5' XSpan casing patch to 3.25" multi-stage setting
tool and running gear. (13.5' CCL to top element). PU and RIH. Pass through T-140 perforations (8694' - 8714') and PU to set depth (8691'-8717.5'). Fired tool,
ignitor initiated but saw no movement with setting sequence. Determined patch had partial set, no joy moving line up or down. Proceeded to pull line out of rope
socket at 3600 lbs. Confirmed line pulled out of cable head, secured well and Rd E-line. Plan forward: Fish patch setting gear with CT.
8/15/2023 PTW, JSA with SLB coil crew, Cruz Crane operator, YJOS tool hand and Hilcorp Rep. Fire equipment. Pick injector head and 40' of lubricator. Make up YJOS
fishing BHA. Coil con, DFCV, Accel jar, weight bar, BIDi jars, Disco, 3" G spear, and bait sub consisting of gutted disco, x over and series 70 grapple overshot
with 1 7/16" catch. ( CC pull tested 25k, MHA PT 3500 psi. ),Stab on well. PT lubricator 250/3500 psi. 0 psi WHP. RIH. Slow down and watch weight at SSSV
and chemical inj. mandrel. Perform weight check prior to tagging fish. Free up weight 28K @ 8500'. E-line TOF found @ 8676'. Set down on TOF at 8679'
CTMD,Work overshot on fish. PU 45K wait for jars. After jars hit straight pull to 52K. Fish came free after 7 down licks and 11 up. POOH with 1500-2000 lbs over
initial free weight of 28K. Tagged up at surface. Break down E line patch tools and fishing tools. Well secured swab and master closed. Break down lubricator rig
back CTU equipment. SDFN.
8/16/2023 PTW, JSA with crew. Make up slim BHA on 1.75" coil. CC, DFCV, Stinger, and nozzle. Stab on well. PT 250/3500 psi. Open well RIH,fluid returns to tank with
coil displacement. well remained full from previous day. Transfer and cool down N2. Online with N2 1200 SCF/min @ 3800' CTMD. Tag PBTD @ 9450' CTMD.
Unload wellbore fluid. Calculated fluid with reel volume is 176 bbls needed. 189 bbls returned. Looks like formation is contributing fluid. POOH to surface and
close choke. Start building WHP. Tagged up. Continue bull heading N2. 1237 psi on tubing. Double block tree with swab and upper master valve. Well secure.
Transport fluids to G&I. Rig down SLB CTU 13. Move to KGF.
8/19/2023 AK E-line arrives on location PTW and PJSM. Resume RU and MU GPT tool string. Move lubricator and tools to well and PT 250/2500 psi. Pass. Open swab
(SITP - 768 psi). RIH with GPT logging survey. Locate fluid level at 8680'. Continue in hole and tag PBTD at 9453'. Open perfs : T-120 (8625' - 8665') & T-145
(8930' - 8945'). Casing patch (8690'-8717'). Commence to perforate the T-146 interval (8980' - 9070'). POOH. OOH. LD GPT and MU Gun #1 (2-3/4" x 18'
(6spf/60D). (9' CCL to top shot). Open swab and RIH. Run correlation and send to RE. Adjust log -1 ft. Confirm on depth. Position gun at 9043' (CCL depth) and
shoot the T-146 interval 9052' - 9070'. Initial: 768 psi 5min: 858 psi 10 min: 896 psi 15 min: 934 psi. POOH. OOH. All shots fired. Gun bull plug full of
sand. AKE crane has mechanical issues not capable of swinging right or left. MU Gun #2 (2-3/4" x 18'). (9' CCL to top shot). Open swab (1173 psi) and RIH.
Correlate and confirm on depth. Position CCL at 9025' and shoot gun at 9034' - 9052'. Initial: 1306 psi 5 min: 1316 psi 10 min: 1323 psi 15 min: 1330
psi. POOH. OOH. Mechanic diagnosing crane problems. LD spent gun, all shots fired. MU Gun #3 (2-3/4" x 18') (9' CCL to top shot). Open swab (1434 psi) and
RIH. Correlate and confirm on depth. Position CCL at 9007' and shoot gun at 9016' - 9034'. Initial: 1504 psi 5 min: 1510 psi 10 min: 1514 psi 15 min:
1518 psi. POOH. At surface. SI swab. Crane out of service. Standby for second crane to arrive. Upon arrival hold PJSM and commence to switch out cranes
utilizing manlift, to switch winches for lifting lubricator. LD lubricator and spent gun. All shots fired. Secure well and SDFN. (1630 psi).
8/20/2023 AK E-line arrives on Paxton pad, obtains PTW and holds PJSM. RIg back on well with Gun #4 (2-3/4" x 18') - (9' - CCL to top shot). SITP - 1945 psi,Open swab
and RIH with Gun #4. Correlate and send logs to RE/Geo. Confirmed on depth. Positioned CCL at 8989' and shoot T-146 interval 8998' - 9016'. Initial: 1989 psi
5 min: 1991 10 min: 1993 psi 15 min: 1994 psi. POOH. OOH. LD spent gun. All shots fired. Wet bull plug. MU Gun #5 (2-3/4" x 18'). (9' CCL to top shot).
Open swab (2000 psi), RIH. Run correlation pass, confirm on depth and position CCL at 8971' and shoot interval 8980' - 8998'. Initial: 2027 psi 5 min: 2029
10 min: 2030 psi 15 min: 2031 psi. POOH. OOH. All shots fired. Gun wet. Secure well. Job complete. RDMO E-line. Last reading: 2050 psi. Field operations
rIg up flow back tank and lines and flow well.
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C
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.04.07 11:37:22 -08'00'Leslie Johnson Digitally signed by Leslie Johnson
Date: 2023.04.17 15:10:12 -05'00'
TD Shoe Depth: PBTD:
Jts.
2
101
Yes X No X Yes No 30
Fluid Description:
Liner hanger Info (Make/Model):Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type:Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type:Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Float shoe 8 5/8
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 4292.18 FC @ Top of Liner4,209.76
Floats Held
Spud Mud
CASING RECORD
County State Alaska Supv.J Murphy / J Richardson
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.NINU Paxton 12 Date Run 25-Mar-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Innovex 1.50 4,292.18 4,290.68
Csg Wt. On Hook:125,000 Type Float Collar:Innovex No. Hrs to Run:8
9.4 5
84
658
FI
R
S
T
S
T
A
G
E
10.5Tune Spacer 60
188.5/194
1347
98
HES
15.8 35.5
Bump press
Visual
Bump Plug?
3:50 3/26/2023 0
4,292.184,297.00 4,209.76
CEMENTING REPORT
Csg Wt. On Slips:65,000
Spud Mud
12 268
Type of Shoe:Innovex Casing Crew:Parker
www.wellez.net WellEz Information Management LLC ver_04818br
4
Ran a total of 50 Hydro forum centralizer
Casing 7 5/8 29.7 L-80 API BTC Tenaris 38.31 4,290.68 4,211.08
Float collar 8 5/8 BTC Innovex 1.32 4,211.08 4,209.76
Casing 7 5/8 29.7 L-80 API BTC Tenaris 4,185.08 4,209.76 24.68
Pup Joint 7 5/8 29.7 L-80 API BTC Tenaris 3.15 24.68 21.53
Hanger 13 5/8 BTC 1.58 21.53 19.95
Type I II 625 2.44
Type I II 173 1.16
5
TD Shoe Depth: PBTD:
Jts.
1
1
144
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? Yes X No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
I II 455 2.39
I II 98 1.24
4
4,087.57 4,054.00
2.25 4,089.82 4,087.57
ZXP WRD-E Liner Top Packer 7 5/8 DWC / C-HT Baker 33.57
4.5'' Liner Pup Jt 4 1/2 12.6 L-80 DWC / C-HT Vam
9,925.94
4.5'' Liner Jts 4 1/2 12.6 L-80 DWC / C-HT Vam 5,836.12 9,925.94 4,089.82
9,967.26 9,927.03
Baker landing Collar 5 BTC JHobbs 1.09 9,927.03
1.28 9,968.54 9,967.26
4.5'' Liner Jt 4 1/2 12.6 L-80 BTC Vam 40.23
Float Collar 5 BTC Baker
4.5'' Liner Jt 4 1/2 12.6 L-80 BTC Vam 40.73 10,009.27 9,968.54
Baker ZXP HRD-E
www.wellez.net WellEz Information Management LLC ver_04818br
3
Type of Shoe:Eccentric Downjet Nose Casing Crew:Parker TRS
12 194
10,011.0010,012.00 9,925.94
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL Polymer
23:42 4/6/2023 4,212
15.3 22
Bump press
CBL 4-21-23
Bump Plug?
144/144.8
1650
0
Halliburton
FI
R
S
T
S
T
A
G
E
10.5Tuned Prime 30
9.5 4
70
1115
Csg Wt. On Hook: Type Float Collar: No. Hrs to Run:
BTC Innovex 1.73 10,011.00 10,009.27
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.NINU Paxton 12 Date Run 6-Apr-23
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
9,966.00
Floats Held3500
6% KCL Polymer Mud
Rotate Csg Recip Csg Ft. Min. PPG9.5
Shoe @ 10010 FC @ Top of Liner 4047
Casing (Or Liner) Detail
Float Shoe 5
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:Cody Dinger
Cc:Jacob Flora; Monty Myers; Donna Ambruz; Guhl, Meredith D (OGC)
Subject:RE: Paxton 12 10-407 Extension Request (PTD #223-014 / Sundry #323-210)
Date:Monday, July 24, 2023 12:29:00 PM
Cody,
Hilcorp is authorized to wait an additional 30 days to allow for well performance monitoring and
additional perforations before filing the 10-407 for this well. The 10-407 revised due date is
8/27/23.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Cody Dinger <cdinger@hilcorp.com>
Sent: Monday, July 24, 2023 11:10 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Monty Myers <mmyers@hilcorp.com>; Donna Ambruz
<dambruz@hilcorp.com>
Subject: Paxton 12 10-407 Extension Request (PTD #223-014 / Sundry #323-210)
Bryan,
Hilcorp is requesting permission to keep Sundry 323-210 (Paxton 12 Initial Completion/Perf) open
past the 30 day window to closeout with a 10-407 (current due date 7/28/23) . The well was
brought online 5/23/23 for a couple weeks before initial perforations were plugged. The well was
perforated (T120) and brought online again 6/14/23 with promising initial rates but have fallen off
significantly since. Hilcorp is currently performing some compression upgrades on the Paxton pad
that should be done in the next couple weeks, it is our desire to see how the well performs once that
comes online and make a decision to either keep the T120 online or perforate up the hole per
sundry 323-210. We suspect additional perforations will be required.
Can we keep this sundry active so we can monitor this well for another 30 days please?
If you need any information or anything additional let Jake or I know.
Thank you!
Cody Dinger
Hilcorp Alaska, LLC
Drilling Tech
907-777-8389
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 07/11/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230711
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
KBU 22-06 50133205500000 205054 7/6/2023
YELLOW
JACKET CBL
KBU 22-06 50133205500000 205054 7/2/2023
YELLOW
JACKET CBL/PERF
KBU 33-06X 50133205290000 203183 6/14/2023
YELLOW
JACKET GPT/PERF
KBU 33-06X 50133205290000 203183 6/29/2023
YELLOW
JACKET GPT/PERF
KBU 33-06X 50133205290000 203183 6/13/2023
YELLOW
JACKET PERF
KU 12-17 50133205770000 208089 6/14/2023
YELLOW
JACKET PERF
MP F-89 50029232680000 205090 7/6/2023 READ Caliper Survey
MP K-05 50029226700000 196068 5/30/2023 READ Caliper Survey
MPU E-23 50029225700000 195094 6/23/2023
YELLOW
JACKET CUT
MPU L-43 50029231900000 203224 6/27/2023
YELLOW
JACKET PERF
PAXTON 12 50133207100000 223014 6/28/2023
YELLOW
JACKET PERF
Please include current contact information if different from above.
T37830
T37830
T37831
T37831
T37831
T37832
T37833
T37834
T37835
T37836
T37837YELLOWPAXTON 12 50133207100000 223014 6/28/2023 PERFJACKET
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.07.11
14:54:56 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 07/10/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230422
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 214-26 50283200830000 212050 6/2/2023 AK E-LINE PPROF
BRU 222-34 50283201860000 222039 6/14/2023 AK E-LINE Perf
BRU 244-27 50283201850000 222038 6/13/2023 AK E-LINE Perf
KBU 33-06X 50133205290000 203183 6/17/2023 AK E-LINE Patch
Paxton 12 50133207100000 223014 6/7/2023 AK E-LINE Perf
PBU 18-29C 50029223160300 209055 6/2/2023 AK E-LINE CBL
Pearl 10 50133207110000 223028 6/6/2023 AK E-LINE Perf
Pearl 11 50133207120000 223032 6/8/2023 AK E-LINE Perf
Please include current contact information if different from above.
PTD: 190-042 T37810
T37811
T37812
T37813
T37814
T37815
T37816
T37817
Paxton 12 50133207100000 223014 6/7/2023 AK E-LINE Perf
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.10
13:32:37 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 06/20/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230419
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BCU 04RD 50133202390100 219011 5/10/2023 AK E-LINE PERF
BRU 212-26 50283201820000 220058 5/31/2023 AK E-LINE PPROF
NCI B-01A 50883200930100 198002 4/24/2023 AK E-LINE Cut CBL CIBP
Paxton 12 50133207100000 223014 5/24/2023 AK E-LINE Perf Record
Paxton 12 50133207100000 223014 4/27/2023 AK E-LINE GPT/PERF
SRU 213B-15 50133206540000 215130 5/1/2023 AK E-LINE CIBP Perf
TBU M-29A 50733204280100 212050 5/7/2023 AK E-LINE Drift Punch
Please include current contact information if different from above.
T37759
T37760
T37761
T37762
T37762
T37763
T37764
Paxton 12 50133207100000 223014 5/24/2023 AK E-LINE Perf Record
Paxton 12 50133207100000 223014 4/27/2023 AK E-LINE GPT/PERF
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.06.20
11:55:19 -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: 5/31/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
PAXTON 12
- PTD 223-014
- API 50-133-20710-00-00
FINAL RADIAL CEMENT BOND LOG (RBT) 04/22/2023
Folder Contents:
Please include current contact information if different from above.
PTD: 223-014
T37681
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.05.31
15:44:43 -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
Date: 05/24/2023
TA' elaclra nil la C.ac ['nncorvntinn ro%rv+n+iccinn
-- - -- - -- --- ---------------
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
PAXTON 12
- PTD 223-014
- AP! 50-133-20710-00-00
Washed and Dried Well Samples (04/03/2023)
B Set (5 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
PAXTON 12
BOX 1 OF 5
4170' - 5400' MD
PAXTON 12
BOX 2 OF 5
5400' - 6600' MD
PAXTON 12
BOX 3 OF 5
6600' - 7800' MD
PAXTON 12
BOX 4 OF 5
7800' - 9000' MD
PAXTON 12
BOX 5 OF 5
9000' - 10014' MD (TD)
Please include current contact information if different from above.
RECENED
NA,AY 2 4 2023
AOGCC
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received Date:
12-'11�1 k) 5 5 (-2-51-2-07 .�2,
1
Regg, James B (OGC)
From:Rance Pederson - (C) <rpederson@hilcorp.com>
Sent:Sunday, April 9, 2023 9:50 AM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT Test Report Rig 169
Attachments:MIT Hilcorp 169 04-08-23.xlsx; Paxton 12 MIT-T and MIT-IA Chart.pdf
Please see the attached MIT test results and chart for Paxton 12 in Ninilchik.
Rance Pederson
Drilling Foreman
Ninilchik Unit
907‐283‐1369 office
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.
Ninilchik Unit Paxton 12PTD 2230140
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230140 Type Inj N Tubing 0 3615 3603 3592 Type Test P
Packer TVD 3218 BBL Pump 1.8 IA 0 100 100 100 Interval I
Test psi 3500 BBL Return 1.9 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230140 Type Inj N Tubing 0 183 189 190 Type Test P
Packer TVD 3218 BBL Pump 1.6 IA 0 3560 3560 3560 Interval I
Test psi 3500 BBL Return 1.4 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:7 5/8" x 4 1/2" Annulus. ZXP Liner Top Packer at 3218' tvd
Notes:
Notes:
Hilcorp Alaska LLC
Ninilchik Field, Ninilchik Unit, Paxton Pad
Josh Riley
04/08/23
Notes:4 1/2" Tieback String and Liner. ZXP Liner Top Packer at 3218' tvd.
Notes:
Notes:
Notes:
Paxton 12
Paxton 12
Form 10-426 (Revised 01/2017)2023-0408_MIT_Ninilchik_Paxton_2tests
J. Regg; 5/8/2023
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 05/05/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: PAXTON 12
PTD: 223-014
API: 50-133-20710-00-00
FINAL OPEN HOLE WIRELINE:
EXT RANGE MICRO IMAGER (XRMI) RAW & PROCESSED (03/24/2023)
Folder Contents (Electronic Plots and Digital Data):
Please include current contact information if different from above.
PTD: 223-014
T37631
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.05.05
10:15:01 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
PAXTON 12
- PTD 223-014
- API 50-133-20710-00-00
FINAL LWD FORMATION EVALUATION LOGS (03/20/2023 to 04/02/2023)
EWR-M5, AGR, DGR, ADR, SLIM EWR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-014
T37620
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.05.01
09:48:56 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Brad Gathman - (C)
Subject:RE: Paxton 12 AOGCC 10-403 (PTD 223-014) - CBL for approval (field copy)
Date:Tuesday, April 25, 2023 4:47:00 PM
Attachments:image002.png
image003.png
Jake,
Hilcorp has approval to proceed with perforating per the approved sundry.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, AK 99501
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Tuesday, April 25, 2023 8:16 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Brad Gathman - (C) <Brad.Gathman@hilcorp.com>
Subject: Paxton 12 AOGCC 10-403 (PTD 223-014) - CBL for approval (field copy)
Hi Bryan,
Please see attached CBL for perforating approval. Note it is a field copy and 10’ off of actual log
depth.
We are planning on shooting the T160 (9484-9513’) this Thursday.
Let me know if you need anything additional.
Thanks,
Jake
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity 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 deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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: 04/21/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: PAXTON 12
PTD: 223-014
API: 50-133-20710-00-00
MUDLOGS - EOW DRILLING REPORTS (03/20/2023 to 04/02/2023)
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 Folder Contents:
Please include current contact information if different from above.
PTD: 223-014
T37617
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.04.24
15:37:15 -08'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, 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?
Will planned perforations require a spacing exception?Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
10,012'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
Jake Flora, Operations Engineer
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
N/A N/A
May 1, 2023
N/A; N/A N/A; N/A
See Schematic See Schematic N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Private
223-014
50-133-20710-00-00
Ninilchik Beluga-Tyonek Gas Same
CO 701F
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Paxton 12
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
8,892'9,925'8,806'2,846'N/A
MD
2,980psi
6,890psi
120'
3,392'
120'
4,292'
Perforation Depth MD (ft):
~5,922 4-1/2"
16"
7-5/8"
120'
4,292'
8,430psi~8,947~10,068
m
n
P
s
t
66
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
323-210
By Kayla Junke at 11:54 am, Apr 06, 2023
Digitally signed by Noel Nocas
(4361)
DN: cn=Noel Nocas (4361),
ou=Users
Date: 2023.04.06 10:36:11 -08'00'
Noel Nocas
(4361)
10-407, combined with drilling PTD.
Submit CBL to AOGCC and gain approval to proceed before perforating.
Passing MITIA required before POP (included as part of PTD).
MDG 4/18/2023
BJM 4/14/23
BOP test to 3500 psi
X
DSR-4/6/23GCW 04/20/23JLC 4/20/2023
04/20/2023
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.04.20 16:24:46
-08'00'
RBDMS JSB 042523
Well Prognosis
Well Name: Paxton 12 API Number: 50-133-20710-00-00
Current Status: Gas Producer Permit to Drill Number: 223-014
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: 3683 psi @ 8372’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2846 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
Paxton 12 is a grass roots well targeting the Beluga and Tyonek sands in the southernmost portion of the
Ninilchik Unit. The objective of this sundry is to blow the wellbore down with coil tubing and perforate multiple
Beluga sands.
Wellbore Conditions:
Drilling will leave the cemented 4.5” liner full of drilling mud, with the 4.5” tubing and annulus displaced to KCL.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 3500 psi Hi 250 Low
4. Clean out wellbore to TD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, PT lubricator to 3500psi, log CBL
6. RIH, reverse out wellbore with nitrogen, trap ~1700 psi on wellbore
7. RDMO coil tubing
8. RU E-line, PT lubricator to 3500 psi
9. Perforate and test the below sands from the bottom up:
Sand MD TOP MD Base Total Ftg TVD TOP TVD
Bot
T65 7683 7755 72 6611 6683
T67 7804 7815 11 6729 6740
T80 7940 7952 12 6862 6874
T81 8038 8051 13 6957 6970
T83 8082 8109 27 6999 7026
T87 8190 8220 30 7103 7133
T115 8461 8497 36 7370 7406
T118 8541 8585 44 7450 7494
T119 8587 8623 36 7496 7532
T120 8625 8665 40 7531 7571
T140 8694 8715 21 7599 7620
T142 8792 8813 21 7694 7715
Well Prognosis
T145 8928 8958 30 7827 7857
T146 8980 9070 90 7879 7969
T160 9484 9513 29 8372 8401
a. All sands lie in the NINILCHIK UNIT, BELUGA-TYONEK GAS POOL
b. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
c. Frac Calcs: Using 12.8 ppg EMW FIT at the surface casing shoe (0.666 psi/ft frac grad)
d. Shallowest Allowable Perf TVD = MPSP/(0.666-0.1) = 2846 psi / 0.566 = 5028‘ TVD
10. RDMO
11. Turn well over to production & flow test well
Attachments:
1. As-built Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
5. AOGCC RWO Change Form
Updated by DMA 04-06-23
CURRENT SCHEMATIC
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,925 / TVD = 8,806’
TD = 10,010’ / TVD = 8,892’
RKB to GL = 18’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” ~4,146’ ~10,068’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf ~4,145’
1
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ~4,146’ 4.875” 6.540” Liner hanger / LTP Assembly
2 ~4,146’ 4.790” 6.340” Seal Stem
3 ~1,500’ 3.958” 4.500” Chemical Injection Sub
4 ~150’ 3.613” 5.500” SSSV
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
3
4
Updated by DMA 04-06-23
PROPOSED SCHEMATIC
Ninilchik Unit
Paxton 12
PTD: 50-133-20710-00-00
API: 223-014
PBTD = 9,925 / TVD = 8,806’
TD = 10,012’ / TVD = 8,892’
RKB to GL = 18’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16”
Conductor –
Driven to Set
Depth
84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 CDC 6.875” Surf 4,292’
4-1/2" Prod Lnr 12.6 L-80 DWC/C HT 3.958” ~4,146’ ~10,068’
4-1/2" Prod Tieback 12.6 L-80 DWC/C HT 3.958” Surf ~4,145’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ~150’ 3.613” 5.500” SSSV
2 ~1,500’ 3.958” 4.500” Chemical Injection Sub
3 4,146’ 4.790” 6.340” Seal Stem
4 4,146’ 4.875” 6.540” Liner hanger / LTP Assembly
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface: 268 bbls 12# lead, 35 bbls 15.8# tail.
4-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T65 ±7,683' ±7,755' ±6,611' ±6,683' 72’ Proposed TBD
T67 ±7,804' ±7,815' ±6,729' ±6,740' 11’ Proposed TBD
T80 ±7,940' ±7,952' ±6,862' ±6,874' 12’ Proposed TBD
T81 ±8,038' ±8,051' ±6,957' ±6,970' 13’ Proposed TBD
T83 ±8,082' ±8,109' ±6,999' ±7,026' 27’ Proposed TBD
T87 ±8,190' ±8,220' ±7,103' ±7,133' 30’ Proposed TBD
T115 ±8,461' ±8,497' ±7,370' ±7,406' 36’ Proposed TBD
T118 ±8,541' ±8,585' ±7,450' ±7,494' 44’ Proposed TBD
T119 ±8,587' ±8,623' ±7,496' ±7,532' 36’ Proposed TBD
T120 ±8,625' ±8,665' ±7,531' ±7,571' 40’ Proposed TBD
T140 ±8,694' ±8,715' ±7,599' ±7,620' 21’ Proposed TBD
T142 ±8,792' ±8,813' ±7,694' ±7,715' 21’ Proposed TBD
T145 ±8,928' ±8,958' ±7,827' ±7,857' 30’ Proposed TBD
T146 ±8,980' ±9,070' ±7,879' ±7,969' 90’ Proposed TBD
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well Paxton 12 (PTD 223-014) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________NINILCHIK UNIT PAXTON 12
JBR 04/27/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Tested with 2 7/8" test joint, CMV #9 Failed to hold dp, greased,functioned and retest(fail ), Change out valve, retest , Pass.
FSV failed to hold dp, C/O, test new FSV (pass)
Test Results
TEST DATA
Rig Rep:Jon Van EveraOperator:Hilcorp Alaska, LLC Operator Rep:Jay Murphey
Rig Owner/Rig No.:Hilcorp 169 PTD#:2230140 DATE:3/27/2023
Type Operation:DRILL Annular:
250/2500Type Test:INIT
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopSTS230329090349
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
3042
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 FP
Inside BOP 1 P
FSV Misc 0 NA
15 FPNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"P
#1 Rams 1 vari 2 7/8"x5 P
#2 Rams 1 blinds P
#3 Rams 1 vari 2 7/8"x 5 P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8"& 2 1/1 P
Kill Line Valves 1 2 1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1600
200 PSI Attained P16
Full Pressure Attained P92
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2500
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P14
#1 Rams P4
#2 Rams P4
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9
9999
9
9
9
FP
FP
CMV #9 Failed
FSV failed to hold dp,
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
Cc:Regg, James B (OGC); Guhl, Meredith D (OGC)
Subject:Re: Paxton 12 AOGCC 10-403 PTD 223-014 Submitted 04-06-23 - Sundry Application
Date:Thursday, April 20, 2023 1:26:42 PM
Attachments:image001.png
image001.png
Jake
Hilcorp has verbal approval to perform the CT Cleanout, CBL, blowdown per the submitted
sundry. AOGCC needs to review the CBL logs before perforating anyway. BOP Test to 3500
psi. Provide 24 hrs opportunity for AOGCC Witness.
Bryan
Sent from my iPhone
On Apr 19, 2023, at 6:06 PM, Jacob Flora <Jake.Flora@hilcorp.com> wrote:
Hi Bryan,
While waiting for the approved completion sundry would it be possible to obtain
approval on the coil cleanout/CBL/N2 blowdown? Brad is mobilizing coil and tanks out
there tomorrow and I would suspect he gets rigged up and BOP tested. We have a
3500 psi BOP test planned for the 2846 psi MPSP.
Greatly appreciated,
Jake
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Thursday, April 6, 2023 10:39 AM
To: aogcc.permitting@alaska.gov
Cc: Jacob Flora <Jake.Flora@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>
Subject: Paxton 12 AOGCC 10-403 PTD 223-014 Submitted 04-06-23 - Sundry
Application
Application for Sundry Approval
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for
the use of 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.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________NINILCHIK UNIT PAXTON 12
JBR 04/17/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:The Diverter vent line had 2 45deg turns in it. I ask Rance to clear them with Jim Regg before moving forward. Rance called me telling he did so.
TEST DATA
Rig Rep:Jon Van EveraOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson
Contractor/Rig No.:Hilcorp 169 PTD#:2230140 DATE:3/20/2023
Well Class:Inspection No:divRCN230320145744
Inspector Bob Noble
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:NA NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:9.875 P
Vent Line(s) Size:16 P
Vent Line(s) Length:142.6 P
Closest Ignition Source:77.8 P
Outlet from Rig Substructure:102.6 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:28 P
Knife Valve Open Time:2 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1500
200 psi Recharge Time:P27
Full Recharge Time:P112
Nitrogen Bottles (Number of):P4
Avg. Pressure:P2525
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
NA NAMud System Misc:
9
9 9
9
5HFHLYHGFDOOIURP5DQFH3HGHUVRQ +LOFRUS RN
GGHJUHH
EHQGVLQGLYHUWHUYHQWOLQH-5HJJ
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Ninilchik Unit, Beluga/Tyonek Gas Pool, Paxton 12
Hilcorp Alaska, LLC
Permit to Drill Number: 223-014
Surface Location: 832’ FNL, 3092’ FEL, Sec 13, T1S, R14W, SM, AK
Bottomhole Location: 1223’ FSL, 423’ FWL, Sec 13, T1S, R14W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run
must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of March, 2023. 15
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.03.15 16:08:22
-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: 10,068' TVD: 8,947'
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): 166.6' 15. Distance to Nearest Well Open
Surface: x-206234 y- 2230533 Zone-4 148.6' to Same Pool: 1508' to Pearl 2A
16. Deviated wells: Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 47 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 CDC 4,346' Surface Surface 4,346' 3,441'
6-3/4" 4-1/2" 12.6# L-80 DWC/C HT 5,922' 4,146' 3,285' 10,068' 8,947'
Tieback 4-1/2" 12.6# L-80 DWC/C HT 4,146' Surface Surface 4,146' 3,285'
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
Paxton 12
Ninilchik Unit
Beluga/Tyonek Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
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 - 1068 ft3 / T 104 ft3
3042
2500’ FSL, 1197’ FWL, Sec 13, T1S, R14W, SM, AK
1223’ FSL, 423’ FWL, Sec 13, T1S, R14W, SM, AK
LOCI 04-007
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
832’ FNL, 3092’ FEL, Sec 23, T1S, R14W, SM, AK Private
~142
18. Casing Program: Top - Setting Depth - BottomSpecifications
3937
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 1310 ft3 / T - 182 ft3
LengthCasing
Conductor/Structural
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Drilling Manager
Monty Myers
4/1/2023
1133' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
907-777-8413
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):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
2.21.2023
By Samantha Carlisle at 11:06 am, Feb 21, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.21 09:06:53 -09'00'
Monty M
Myers
Spacing exception req'd: Yes
SFD 3/15/2023
13 SFD 3/6/2023
223-014 50-133-20710-00-00
GCW 03/15/23JLC 3/15/2023
3/15/23
3/15/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.03.15 16:09:12 -08'00'
Paxton 12
Drilling Program
Ninilchik Unit
February 1, 2023
Revision 0
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 9-7/8” Hole Section .......................................................................................................... 13
12.0 Run 7-5/8” Surface Casing ...................................................................................................... 15
13.0 Cement 7-5/8” Surface Casing ................................................................................................. 18
14.0 BOP N/U and Test.................................................................................................................... 21
15.0 Drill 6-3/4” 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 .................................................................................................................. 31
20.0 Diverter Schematic .................................................................................................................. 34
21.0 BOP Schematic ........................................................................................................................ 35
22.0 Wellhead Schematic ................................................................................................................. 36
23.0 Days Vs Depth .......................................................................................................................... 37
24.0 Geo-Prog .................................................................................................................................. 38
25.0 Anticipated Drilling Hazards .................................................................................................. 39
26.0 Hilcorp Rig 169 Layout ........................................................................................................... 41
27.0 FIT/LOT Procedure................................................................................................................. 42
28.0 Choke Manifold Schematic ...................................................................................................... 43
29.0 Casing Design Information ...................................................................................................... 44
30.0 6-3/4” Hole Section MASP ....................................................................................................... 45
31.0 Spider Plot (Governmental Sections) ...................................................................................... 46
32.0 660’ Radius for SSSV ............................................................................................................... 47
33.0 Surface Plat (As-Built NAD27) ................................................................................................ 48
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1.0 Well Summary
Well Paxton 12
Pad & Old Well Designation Paxton Pad / grassroots well
Planned Completion Type 4-1/2” Cemented Production Liner
Target Reservoir(s) Beluga/Tyonek Gas Sands
Planned Well TD, MD / TVD 10,068’ MD / 8,947’ TVD
PBTD, MD / TVD 9,988’ MD / 8,869’ TVD
Surface Location (Governmental) 832’ FNL, 3092’ FEL, Sec 23, T1S, R14W, SM, AK
Surface Location (NAD 27) X=206234.63 Y=2230533.10
Top of Productive Horizon
(Governmental) 2500’ FSL, 1197’ FWL, Sec 13, T1S, R14W, SM, AK
TPH Location (NAD 27) X=205197.25, Y=2228520.34
BHL (Governmental) 1223’ FSL, 423’ FWL, Sec 13, T1S, R14W, SM, AK
BHL (NAD 27) X=204393.09, Y=2227262.04
AFE Number
AFE Drilling Days 4 MOB, 27 DRLG
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface) 3042 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 3937 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 166.6’ (148.6 + 18)
Ground Elevation 148.6’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
13 SFD 3/6/2023
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16” 15.01”14.822”- 84 X-56 Weld 2980 1410 -
Surface
9-7/8” 7-5/8” 6.875”6.750”8.500”29.4 L-80 BTC 6890 4790 683
Prod
6-3/4” 4-1/2” 3.958”3.833”5.000”12.6 L-80 DWC/C-HT 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25” 16.6 S-135 CDS40 17,693 16,769 468k
Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellView.
Report covers operations from 6am to 6am
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.
Ensure time entry adds up to 24 hours total.
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
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
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
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
Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final “As-Run” Casing tally to mmyers@hilcorp.com,Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
Paxton 12 is a grassroots development well to be drilled from Paxton Pad. This well will be targeting the
Beluga and Tyonek sands identified for gas production based on the data from the Pearl Pad wells and
Paxton 6.
The base plan is a directional wellbore with a kickoff point at ~250’ MD. Maximum hole angle will be ~45
deg before dropping to 12 deg and TD of the well will be 10,068’ TMD/ 8,947’ TVD.
Drilling operations are expected to commence approximately April 1, 2023. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to ~4,346’ MD / 3,442’ 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 # 169 to well site
2. N/U Diverter
3. Drill 9-7/8” hole to 4,346’ MD.
4. Run and cement 7-5/8” surface casing.
5. ND conductor riser, N/U & test 11” x 5M BOP.
6. Drill Out shoe and perform FIT.
7. Drill 6-3/4” hole section to 10,068’ 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:
1. Surface Hole: Triple Combo MWD w/e-line image log after TD
e-line logs dependent on hole conditions
2. Production Hole: Triple Combo MWD w/e-line sonic and image logs after TD
e-line logs dependent on hole conditions
3. Mud loggers from surface casing point to TD.
Surface casing will be run to ~4,346’ MD / 3,442’ TVD
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
BOPs shall be tested at (2) week intervals during the drilling of PAXTON 12. Ensure to provide
AOGCC at least 24 hrs notice prior to testing BOPs.
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.
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.
All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office.
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:
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”21-1/4” x 2M diverter Function Test Only
6-3/4”
11” x 5M Annular BOP
11” x 5M Double Ram
o Blind ram in btm cavity
Mud cross
11” x 5M Single Ram
3-1/8” 5M Choke Line
2-1/16” x 5M Kill line
3-1/8” x 2-1/16” 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing Diverter and BOPs.
24 hours notice prior to casing running & cement operations.
48 hours notice prior to performing MITIA.
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 # 169, 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 9-7/8” hole section.
9.9 Install 5-1/2” liners in mud pumps.
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
N/U 21-1/4” diverter “T”.
Knife gate, 16” diverter line.
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.
NOTE:Ensure closing time on diverter annular is in line with API RP 64:
o Annular element ID 20” or smaller: Less than 30 seconds
o 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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
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10.5 Rig 169 Orientation:
Note: Actual layout may be different on location
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11.0 Drill 9-7/8” Hole Section
11.1 P/U 9-7/8” directional drilling assy:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8” hole section to 4,346’ MD/ 3,442’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
Utilize past experience to drill through coal seams efficiently. Coal seam log will be
provided by Hilcorp Geo team.
Keep swab and surge pressures low when tripping.
Make wiper trips every 500’-1000’ unless hole conditions dictate otherwise.
Ensure shale shakers are functioning properly. Check for holes in screens on connections.
Adjust MW as necessary to maintain hole stability.
Take MWD surveys every stand drilled (60’ intervals).
11.5 9-7/8” hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-4346’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
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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 7-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 7-5/8” casing running equipment.
Ensure 7-5/8” BTC x CDS 40 XO on rig floor and M/U to FOSV.
R/U fill-up line to fill casing while running.
Ensure all casing has been drifted on the location prior to running.
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
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:
(1) Shoe joint w/ float shoe bucked on (thread locked).
(1) Joint with coupling thread locked.
(1) Joint with float collar bucked on pin end & thread locked.
Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
Install (1) centralizer, mid tube on thread locked joint and on FC joint.
Ensure proper operation of float equipment.
12.5 Continue running 7-5/8” surface casing
Fill casing while running using fill up line on rig floor.
Use “API Modified” thread compound. Dope pin end only w/ paint brush.
Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
Utilize a collar clamp until weight is sufficient to keep slips set properly.
7-5/8” 29.7# BTC M/U torques
Casing OD Makeup
7-5/8” To Mark
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 7-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
How to handle cmt returns at surface.
Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
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 7-5/8”
casing annulus:
120’ x .16239 bpf = 19.49 109.4
12.0 ppg LEAD:
9-7/8” OH x 7-5/8” Casing
annulus:
(3846’ – 120’) x .03825 bpf x
1.5 =
213.78 1200.3
Total LEAD: 233.27 bbl 1309.7 ft3
15.4 ppg TAIL:
9-7/8” OH x 7-5/8” Casing
annulus:
(4346’- 3846’) x .03825 bpf x
1.5 =
28.69 161.1
15.4 ppg TAIL:
7-5/8” Shoe track:
80 x .04592 bpf = 3.67 20.6
Total TAIL: 32.36 bbl 181.7 ft3
TOTAL CEMENT VOL: 265.63 bbl 1491.4 ft3
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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:
4346’- 80’ = 4266’ x .04592 bpf = 196 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.13 Do not overdisplace by more than ½ shoe track volume. Total volume in shoe track is 3.6 bbls.
Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 – 18 hours after CIP.
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 (3846’ MD to surface)Tail Slurry (4346’ to 3846’ MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.40 ft3/sk 1.16 ft3/sk
Mixed Water 14.25 gal/sk 5.04 gal/sk
Mixed Fluid 14.25 gal/sk 5.04 gal/sk
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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:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
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 multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
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
Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
Single ram should be dressed with 2-7/8” x 5” variable bore rams
N/U bell nipple, install flowline.
Install (2) manual valves & a check valve on kill side of mud cross.
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).
Test BOP to 250/3500 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
Utilize both 4-1/2” and 2-7/8” test joints to be set up for production casing cleanout run.
Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.0 ppg 6% KCL PHPA mud system. If MW at surface TD was greater than 9.0 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 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing.
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH, 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 6-3/4” hole section mud program summary:
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
4,346’- 10,068’ 9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation:6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 – 10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on
FIT/LOT graph. AOGCC requirement is 50% of burst.7-5/8” burst is 6890 psi / 2 = 3445 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 12.6 ppg EMW.
Note: Offset field test data predicts frac gradient at the 7-5/8” shoe to be between 11.5 – 21.0
ppg EMW. A 12.6 ppg FIT results in a >15 bbl kick tolerance while drilling with the planned
MW of 9.8 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
15.14 Drill 6-3/4” hole section to 10,068’ MD / 8,947’ TVD
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Pump at 250 - 350 gpm. Ensure shaker screens are set up to handle this flowrate.
Keep swab and surge pressures low when tripping.
Make wiper trips every 1000’ unless hole conditions dictate otherwise.
On the third wiper trip (around 7,200’ MD), trip back to the 7-5/8” shoe to split the hole
section in half.
Ensure shale shakers are functioning properly. Check for holes in screens on connections.
Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
Collect samples every 20’.
NOTE: Running Coals in Tyonek required a 9.8ppg after TD on Pearl 2A. Be ready to
weight up if needed for hole stability. See section 25.0.
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15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. NOTE (again): be
prepared to increase mud weight prior to final wiper trip to address potential coal stability issues
that were encountered in Pearl 2A.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RU E-Line and perform wireline logging plan.
15.19 RD E-Line. PU 6-3/4” clean out BHA, and TIH to TD.
15.20 Pump sweep, CBU and condition mud for casing run.
15.21 POOH and LD BHA
15.22 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.
Ensure 4-1/2” DWC/C-HT x CDS 40 crossover on rig floor and M/U to FOSV.
R/U fill up line to fill liner while running.
Ensure all liner has been drifted prior to running.
Be sure to count the total # of joints before running.
Keep hole covered while R/U liner tools.
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:
(1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
(1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
(1) Joint with Baker landing collar bucked on pin end & threadlocked.
Solid body centralizers will be pre-installed on shoe joint, FC joint, and landing collar joint.
Leave centralizers free floating so that they can slide up and down the joint.
Ensure proper operation of float shoe and float collar.
Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 4-1/2” production liner
Fill liner while running using fill up line on rig floor.
Use “API Modified” thread compound. Dope pin end only w/ paint brush.
Install solid body centralizers on every joint across zones of interest, TBD after LWD.
Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 4-1/2” production liner
4-1/2” 12.6 DWC/C-HT M/U torques
Casing OD Minimum Maximum Yield Torque
4-1/2” 5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs
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16.6. Run in hole w/ 4-1/2” liner to the 7-5/8” 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 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight, and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. 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.
Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
Positions and expectations of personnel involved with the cmt operation.
Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .02624 bpf = 5.25 29.5
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” liner
annulus:
200’ x .02624 bpf = 5.25 29.5
12.0 ppg LEAD:
6-3/4” OH x 4-1/2” annulus:
(9568’ – 4346’) x .02459 bpf x
1.4 =
179.77 1009.3
Total LEAD: 190.27 bbl 1068.3 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(10068’- 9568’) x .02459 bpf
x 1.4 =
17.21 96.6
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf = 1.22 6.8
Total TAIL: 18.43 bbl 103.5 ft3
TOTAL CEMENT VOL: 208.70 bbl 1171.8 ft3
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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 (9568’ MD to 4146’ MD)Tail Slurry (10068’ to 9568’ MD)
System Extended Conventional
Density 12 lb/gal 15.3 lb/gal
Yield 2.4 ft3/sk 1.24 ft3/sk
Mixed Water 14.09 gal/sk 5.58 gal/sk
Mixed Fluid 14.09 gal/sk 5.58 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:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if liner is reciprocated or rotated during the job
Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
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.
18.4. Test casing and liner lap to 3,500 psi / 30 min. Ensure to chart record casing test.
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.
Install Chemical injection mandrel at ~500’. Detail to be learned for OE. OD should be 5.9”
Install SSSV at ~150’ in tieback string
o Dual control line spooler needed
4-1/2” 12.6# DWC/C-HT M/U torques
Casing OD Minimum Maximum Yield Torque
4-1/2” 5,800 ft-lbs 6,500 ft-lbs 9,240 ft-lbs
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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. 24hr AOGCC
notice required.
19.7 Test 7-5/8” x 4-1/2” annulus to 3,500 psi / 30 min and chart for 30 minutes.24hr 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
16'’
Hydril V
4.30'Hydril
MSP 21-¼ 2M
.50'
4.00'
2.67'
1.33'
4.37'
Grade Level
3.09'
DSA 16 ¾ 3M X 21 ¼ 2M
21 ¼ 2M
Spool
21 ¼ 2M
Diverter Tee
16'’ 150 outlet
4.08'
16'’ casing cut @ 64'’
below ground level
.42'
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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
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25.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 – 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 – 30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in KU 42-12 when drilling through Pool 6, ensure all LCM
inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Hole stability issues in the Tyonek were seen in Pearl 2A (March, 2022). Weight up of 0.5ppg from
9.3ppg to 9.8ppg allowed for openhole logging and liner running/cementing.
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.
Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
Use asphalt-type additives to further stabilize coal seams.
Increase fluid density as required to control running coals.
Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
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26.0 Hilcorp Rig 169 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
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30.0 6-3/4” Hole Section MASP
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31.0 Spider Plot (Governmental Sections)
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32.0 660’ Radius for SSSV
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33.0 Surface Plat (As-Built NAD27)
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
Beluga/Tyonek Gas
Paxton 12
223-014
Ninilchik
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PAXTON 12Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230140NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes Private land2 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA/TYONEK GAS – 562503, governed by CO 701C4 Well located in a defined poolNo Spacing exception needed as well lies within 1500' of a property line where landownership changes.5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedNo9 Operator only affected partyYes10 Operator has appropriate bond in forceNo11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 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 = 3042 psi, 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 anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal pressure gradient expected except for Tyonek T-146 reservoir which is underpressured (0.34 psi/ft; 6.536 Data presented on potential overpressure zonesNA ppg EMW). Operator's planned mud program appears adequate to mitigate expected reservoir pressures.37 Seismic analysis of shallow gas zonesNA Some potential for running coals and wellbore instability along with lost curculation,. Mitigation discussed38 Seabed condition survey (if off-shore)NA on pages 40 and 40.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate3/15/2023ApprBJMDate3/7/2023ApprSFDDate3/6/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 03/15/23JLC 3/15/2023
