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Alaska Oil and Gas Conservation Commission
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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: 1/28/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240128
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet #
BCU 14B 50133205390200 222057 10/21/2024 YELLOWJACKET GPT-PLUG-PERF
BRU 232-04 50283100230000 162037 1/8/2025 AK E-LINE TubingPlugCut
BRU 241-34S 50283201980000 224077 1/11/2025 AK E-LINE Perf
END 2-16 50029218850000 188134 10/6/2024 YELLOWJACKET PERF
MPU H-08B 50029228080200 201047 1/9/2025 READ CaliperSurvey
MRU M-25 50733203910000 187086 1/2/2025 AK E-LINE Perf
PEAR 11 50133207120000 223032 10/2/2024 YELLOWJACKET PLUG-PERF
Please include current contact information if different from above.
T40025
T40026
T40027
T40028
T40032
T40033
T40035PEAR 11 50133207120000 223032 10/2/2024 YELLOWJACKET PLUG-PERF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.01.29 10:55:36 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/05/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241217
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT
BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF
BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF
BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF
HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT
KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF
KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting
KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf
KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL
MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF
MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL
MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement
MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf
PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL
PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM
PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM
PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN
PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM
PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN
PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN
PBU L3-22A 50029216630100 219051 10/9/2024 BAKER
PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF
PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF
SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF
Please include current contact information if different from above.
T39863
T39864
T39865
T39868
T39869
T39870
T39871
T39872
T39873
T39875
T39874
T39867
T39866
T39876
T39877
T39880
T39878
T39879
T39881
T39882
T39883
T39884
T39885
T39886
T39887
PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.12.18 08:35:44 -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: N2
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 8,613 feet See Schematic feet
true vertical 7,892 feet N/A feet
Effective Depth measured 4,270 feet 2,708 feet
true vertical 3,734 feet 2,434 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 2,717' MD 2,441' TVD
Packers and SSSV (type, measured and true vertical depth) Swell Pkr; HES TRSV 2,708' MD 2,434' TVD 144' MD/TVD
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
7,500psi
2,980psi
6,880psi
8,430psi
2,892' 2,587'
Burst Collapse
1,410psi
4,790psi
Production
Liner
5,844'
Casing
Structural
7,832'8,553'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
2,892'
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-032
50-133-20712-00-00
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:
ADL0384372 / FEE-PRIVATE
Ninilchik / Beluga-Tyonek Gas
Pearl 11
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
60
Size
120'
0 520
0 8410
34
Scott Warner, Operations Engineer
324-440
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
21
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
scott.warner@hilcorp.com
907-564-4506
p
k
ft
t
Fra
O
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6. A
G
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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 10:48 am, Oct 21, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.10.17 16:26:42 -
08'00'
Noel Nocas
(4361)
Page 1/1
Well Name: NINU Pearl 11
Report Printed: 10/17/2024WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:8/31/2024 End Date:
Report Number
1
Report Start Date
8/26/2024
Report End Date
8/26/2024
Last 24hr Summary
Tag Fluid at 3180' RKB Tag Fill above CIBP at 8113' RKB
Report Number
2
Report Start Date
8/29/2024
Report End Date
8/29/2024
Last 24hr Summary
PTW/PJSM. FTP 37 psi @ 0 MSCFD. MIRU Fox N2 and YJ E-line. RU fox hardline to wellhead and pt to 5k psi - good test. PT lubricator to 250/3000 psi- good
test. RIH w/ GPT, fluid level @ 2,550'. POOH and pump N2 @ 1300 SCFM to 3385 psi. RIH with GPT and did not see a fluid level. Set CIBP @ 7,626' and
confirm w/ tag. Bleed SITP to 1818 psi and RIH w/ 10' of 2 3/4" guns. Perforate T65 f/ 7,358'-7,368'. POOH and secure well.
Report Number
3
Report Start Date
8/30/2024
Report End Date
8/30/2024
Last 24hr Summary
PTW/PJSM. SITP 18 psi. RU YJ E-line and Fox N2. RIH w/ GPT and find fluid level @ 7,430' (below perfs). Pump N2 and pressure well up to 2000 psi. RIH w/
10' of 2 3/4" guns. Perforate T45 f/ 6,730'-6,740'. Bleed well pressure to zero - no flow. RIH w/ GPT and find fluid level @ 7,390' (below perfs). Hook up HP gas
jumper to pressure up well. RIH w/ fluid sample catcher. RIH w/ 30' of 2 3/4" guns. Perforate T19 f/ 6,170'-6,200'. POOH and secure well.
Report Number
4
Report Start Date
8/31/2024
Report End Date
8/31/2024
Last 24hr Summary
PTW/PJSM. SITP 60 psi. RU YJ E-line and Fox N2. RIH w/ GPT and find fluid level @ 6,800' (below perfs). Pump N2 and pressure well up to 1800 psi. RIH w/
20' of 2 3/4" switch guns. Perforate T7 f/ 4,897'-4,907' and T6a f/ 4,791'-4,801'. Bleed well to zero - no flow. RIH w/ GPT and find fluid level @ 6,535' (below future
perfs). Pressure up well with HP gas. RIH w/ 30' of 2 3/4" switch guns. Perforate T6 f/ 4,751'-4,761', T6 f/ 4,722'-4,732', and T5a f/ 4,608'-4,618'. POOH, LD guns
and lubricator, secure well and hand over to production.
Report Number
5
Report Start Date
9/1/2024
Report End Date
9/1/2024
Last 24hr Summary
PTW/PJSM. SITP 80 psi. RU YJ E-line. RIH w/ GPT and find fluid level @ 4,160' (above future perfs). Pressure up with HP gas to push water away. RIH w/
CIBP and find fluid level @ 4,370' and set CIBP @ 4,600'. RIH w/ dump bailer and dump 25' (16 gals) of cement (2 runs). RIH w/ 30' of 2 3/4" switch guns.
Perforate T2 (4,341-4,351), T2 (4,316-4,326), and T2 (4,282-4,292). POOH, LD guns and lubricator, secure well and hand over to production.
Report Number
6
Report Start Date
10/2/2024
Report End Date
10/3/2024
Last 24hr Summary
PTW / PJSM with Fox N2 and YJ Eline. RU N2 pump and E-line equipment. PT 250/3500 psi. Pump N2 at 1000 scfm, pressure broke over at 2050 psi (60K scf
away). SD pump, RIH with GPT and fluid sample catcher. Locate fluid level at 4351' (lowest T2 perf), drop down and collect fluid sample. Set CIBP at 4270'. Bleed
well down to 1000 psi, RIH with two gun runs and perforate the BEL-115 intervals 3904'-3914' and 3880'-3900'. SITP 1055 psi. Secure well, RD E-line and hand
over to production to flow test.
Field: Ninilchik
Sundry #: 324-440
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-032Permit to Drill (PTD) #:223-032
Wellbore API/UWI:50-133-20712-00-00
Updated by DMA 10-09-24
SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488 / TVD = 7,768
TD = 8,613 / TVD = 7,892
RKB to GL = 18
4270
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 2,892
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958 2,709 8,553
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958 Surf 2,717
4
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 144 3.813 5.500 SSSV
2 1,524 3.958 4.500 Chemical Injection Sub
3 2,709 4.875 6.540 Liner hanger / LTP Assembly
4 2,717 4.790 6.340 Seal Stem
5 4,270 3.5 CIBP (10/2/24)
6 4,600 3.5 CIBP (9/1/24) w/25 cement TOC @ 4,575
7 7,626 3.5 CIBP (8/29/24)
8 8,115 3.5 CIBP (7/9/24)
9 8,380 3.5 CIBP (6/25/24)
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2 TOC @ 2980 (CBL: 6/6/2023)
6-3/4
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Bel 115 3,880' 3,900' 3,409' 3,426' 20' 10/2/2024 Open
Bel 115 3,904' 3,914' 3,429' 3,437' 10' 10/2/2024 Open
T2 4,282' 4,292' 3,744' 3,753' 10' 9/1/2024 Isolated
T2 4,316' 4,326' 3,773 3,781 10' 9/1/2024 Isolated
T2 4,341' 4,351' 3,793 3,802 10' 9/1/2024 Isolated
T5A 4,608' 4,618' 4,017' 4,025' 10' 8/31/2024 Isolated
T6 4,722' 4,732' 4,114 4,123 10' 8/31/2024 Isolated
T6 4,751' 4,761' 4,139 4,148 10' 8/31/2024 Isolated
T6A 4,791' 4,801' 4,174' 4,183' 10' 8/31/2024 Isolated
T7 4,897' 4,907' 4,267 4,276 10' 8/30/2024 Isolated
T19 6,170' 6,200' 5,485' 5,515' 30' 8/30/2024 Isolated
T45 6,730' 6,740' 6,037' 6,047' 10' 8/30/2024 Isolated
T65 7,358' 7,368' 6,656' 6,665' 10' 8/29/2024 Isolated
T-81 7,633' 7,639' 6,926' 6,932' 6' 7/11/2024 Isolated
T-83 7,696' 7,706' 6,988' 6,998' 10' 7/11/2024 Isolated
T-90 7,870' 7,876' 7,160' 7,166' 6' 7/10/2024 Isolated
T-100 7,975' 7,995' 7,263' 7,282' 20' 7/10/2024 Isolated
T-118 8,163' 8,191' 7,448' 7,476' 28' 7/8/2024 Isolated
T142 8,392' 8,412' 8,079 8,099 20' 6/8/2023 Isolated
T118
T81
T90
T100
T142
T83
8
9
Bel 115
5
6
7
T5A-T65
T2
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: 9/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240912
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 7/22/2024 BAKER RPM
Blossom 1 50133206480000 215015 8/31/2024 READ Coilflag
Blossom 1 50133206480000 215015 9/2/2024 READ MemoryRadialCementBondLog
KBY 43-07Y 50133206250000 214019 9/9/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 8/29/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/4/2024 AK E-LINE Plug/Perf
NCIU A-20 50883201960000 224065 8/29/2024 AK E-LINE Perf
NCIU A-20 50883201960000 224065 9/3/2024 AK E-LINE Plug/Perf
PBU N-21A (REVISED) 50029213420100 196196 3/28/2024 BAKER SPN
PBU N-02 50029200830000 170055 7/25/2024 BAKER SPN
PBU S-104 50029229880000 200196 7/7/2024 BAKER SPN
PBU Z-68 50029234930000 213093 7/6/2024 BAKER SPN
Pearl 11 50133207120000 223032 6/24/2024 BAKER SPN
Revision explanation: OmniView .las file was the same as the carbo/oxygen .las file, omniview file
has been replaced with the correct file and data.
Please include current contact information if different from above.
T39545
T39546
T39546
T39547
T39548
T39548
T39549
T39549
T39550
T39551
T39552
T39553
T39554Pearl 11 50133207120000 223032 6/24/2024 BAKER SPN
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.12 12:52:42 -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:AOGCC Records (CED sponsored)
Subject:Fwd: Pearl 11 AOGCC 10-403 324-440 PTD 223-032 Approved 08-07-24
Date:Sunday, September 1, 2024 9:56:44 PM
Please add this email chain to wellfile.
Bryan McLellan
Sent from my iPhone
Begin forwarded message:
From: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov>
Date: September 2, 2024 at 7:55:07 AM GMT+2
To: Scott Warner <Scott.Warner@hilcorp.com>
Subject: Re: Pearl 11 AOGCC 10-403 324-440 PTD 223-032 Approved 08-07-24
Scott,
Following up from our phone discussion and verbal approval, Hilcorp has approval to set plug and
add additional perfs listed in email below.
Bryan McLellan
Sent from my iPhone
On Sep 1, 2024, at 8:01 PM, Scott Warner <Scott.Warner@hilcorp.com> wrote:
Bryan,
With the plug set at 4600’ and planned perforations in the T2 with top perf depth being
4341’ MD/3793’ TVD, the new shallowest allowable perf TVD is 2306’ TVD. We do not plan
to perforate above the BEL 115 which is 3880’ MD/3409’ TVD.
Thanks again for the conversation and sorry to bug you on the holiday weekend.
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
From: Scott Warner <Scott.Warner@hilcorp.com>
Sent: Sunday, September 1, 2024 9:45 AM
To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>
Subject: FW: Pearl 11 AOGCC 10-403 324-440 PTD 223-032 Approved 08-07-24
Bryan,
We have perforated everything in the second table below (T5A-T65) and are looking to
move uphole since none of those perforations have produced gas to surface. Per sundry
conditions of approval, we plan to set a plug at 4600’ and place 25’ of cement on that plug.
Once that plug is set we will then continue to perforate the T2 and BEL 115 sands per table
below.
Well Sand Top MD Btm MD Interval
Pearl 11 BEL115 3880 3900 20
Pearl 11 BEL115 3904 3914 10
Pearl 11 T2 4282 4292 10
Pearl 11
T2 4316 4326 10
Pearl 11 T2 4341 4351 10
Perforated as of 9/1/24:
Well Sand Top MD Btm MD Interval
Pearl 11 T5A 4608 4618 10
Pearl 11 T6 4722 4732 10
Pearl 11 T6 4751 4761 10
Pearl 11
T6A 4791 4801 10
Pearl 11
T7 4897 4907 10
Pearl 11
T19 6170 6200 30
Pearl 11
T45 6730 6740 10
Pearl 11
T65 7358 7368 10
Please let me know if you have any questions.
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Wednesday, August 7, 2024 11:13 AM
To: Scott Warner <Scott.Warner@hilcorp.com>
Cc: Noel Nocas <Noel.Nocas@hilcorp.com>
Subject: Pearl 11 AOGCC 10-403 324-440 PTD 223-032 Approved 08-07-24
FYI – Please distribute as necessary.
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the useof the individual or entity named above. If you are not an intended recipient or if you have received this message in error, youare hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received thisemail in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, thenpromptly 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 ensurethat the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems ordata. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and otherchecks as it considers appropriate.
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,613'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 Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Swell Pkr; HES TRSV 2,708' MD/2,434' TVD;144' MD/TVD
7,892'8,488'7,768'
Ninilchik Beluga-Tyonek Gas
16"
7-5/8"
See Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Pearl 11CO 701H
Same
7,832'4-1/2"
2469 psi
5,844'
8,115 & 8,380
Length
August 13, 2024
Tieback 4-1/2"
8,553'
Perforation Depth MD (ft):
See Schematic
2,980psi
6,880psi
120'120'
2,892'
Size
120'
2,892'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L--80
TVD Burst
2,717'
8,430psi
2,587'
Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0384372 / FEE-PRIVATE
223-032
50-133-20712-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Scott Warner, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
scott.warner@hilcorp.com
907-564-4506
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval.
Authorized Name and
Digital Signature with Date:
P
s
66
2
c
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Noel Nocas
(4361)
Digitally signed by Noel Nocas
(4361)
Date: 2024.07.30 11:39:44
-08'00'
324-440
By Grace Christianson at 11:57 am, Jul 30, 2024
10-404
DSR-8/2/24
Perforating above 4550' MD is not allowed unless a plug is set to isolate deeper perfs with 25' of cement
placed on the plug. Plug and perf depth must be verified and agreed with AOGCC.
A.Dewhurst 05AUG24BJM 8/6/24JLC 8/6/2024
Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.08.07 10:38:53 -08'00'
08/07/24
RBDMS JSB 080824
Well Prognosis
Well: Pearl 11
Well Name: Pearl 11 API Number: 50-133-20712-00-00
Current Status: Producing Gas Well Permit to Drill Number: 223-032
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: 3196 psi @ 7263’ TVD Based on 0.44 psi/ft
Max. Potential Surface Pressure:2469 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: .75 psi/ft using 14.6 ppg EMW FIT at the surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.75-0.1) = 2469 psi / 0.65 = 3798‘ TVD
Top of Applicable Gas Pool: 1680’ MD/ 1581’ TVD
Well Status: Online Gas Producer flowing at 141 mcfd, 0 bwpd, 37 psi FTP
Brief Well Summary
Pearl 11 is a grass roots well drilled in 2023 targeting the Beluga and Tyonek sands in the southernmost portion
of the Ninilchik Unit. Initial perforations were added in the T-142 and came on strong at 9 mmscfd but has
been on steady decline since and ultimately quit flowing. Perforations were added in July 2024 in the Tyonek
81-118 but rate only increased by 175 mscfd.
The purpose of this sundry is to perforate additional footage in the Tyonek 45 to 02 and Beluga 115 sands to
increase production.
Notes Regarding Wellbore Condition
7/11/24 CIBP set at 8,115’. Perforated T-81 to T-100 with 2-3/4” guns
7/8/24 Perforated T-118 from 8,163’- 8,191’
6/25/24 CIBP set at 8,380’
06/08/2023 Perforated T-142 sand from: 8392’-8412’ with 2-3/4” guns
09/21/23 D&T w/ 2.5” DD bailer. Tag fluid @ 8390’S SLM. Tag TD @ 8484’ SLM
Procedure:
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250 psi low / 3,000 psi high
3. PU GPT and RIH to confirm fluid depth
4. RIH and perforate Tyonek 65- BEL115 sands from bottom up with 2-3/4” 60 deg phased perf guns:
Below are proposed targeted sands in order of testing (bottom/up),
but additional sand may be added depending on results of these
perfs, between the proposed top and bottom perfs
Sand Top MD Btm MD Top TVD Btm TVD Interval
BEL115 ±3,880' ±3,900' ±3,409' ±3,426' ±20'
BEL115 ±3,904' ±3,914' ±3,429' ±3,437' ±10'
T2 ±4,282' ±4,370' ±3,744' ±3,817' ±88'
T5A ±4,558' ±4,618' ±3,974' ±4,025' ±60'
T6 ±4,707' ±4,779' ±4,101' ±4,164' ±72'
T6A ±4,791' ±4,801' ±4,174' ±4,183' ±10'
pp
Shallowest Allowable Perf TVD:
Not allowed per calculations
above: shallowest allowable
perf is 4,347' MD / 3,798' TVD.
SFD
3798‘ TVD , equivalent to 4,347' MD SFD
Well Prognosis
Well: Pearl 11
T7 ±4,882' ±4,939' ±4,254' ±4,304' ±57'
T19 ±6,170' ±6,200' ±5,485' ±5,515' ±30'
T45 ±6,730' ±6,740' ±6,037' ±6,047' ±10'
T65 ±7,321' ±7,358' ±6,619' ±6,656' ±37'
a. Proposed perfs are also shown on the proposed schematic in red font
b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to
the Operations Engineer, Reservoir Engineer, and Geologist for confirmation
c. Use Gamma/CCL to correlate
d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min
intervals post perf shot (if using switched guns, wait 10 min between shots)
e. Pending well production, all perf intervals may not be completed
f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
setting a plug above perforations
5. RDMO
a. If necessary, run cap string to aid with water production if encountered post perforating
i. RU Cap String Truck
ii. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components.
Install pack-off and pressure test against swab valve to 2500 psi
iii. RIH with 3/8” capillary string to ±8300’ MD
a. Set cap string as deep as practical in fluid
iv. Install slips and connect tubing to chemical injection pump
v. Set spool of remaining line near well
vi. RD cap string Unit, and turn well over to production
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Standard Well Procedure – N2 Operations
Updated by DMA 07-17-24
SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488’ / TVD = 7,768’
TD = 8,613’ / TVD = 7,892’
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 2,892’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,709’ 8,553’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,717’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.813” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,709’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
5 8,115’ 3.5” CIBP (7/9/24)
6 8,380’ 3.5” CIBP (6/25/24)
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2” TOC @ 2980’ (CBL: 6/6/2023)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T-81 7,633' 7,639' 6,926' 6,932' 6' 07/11/2024 Open
T-83 7,696' 7,706' 6,988' 6,998' 10' 07/11/2024 Open
T-90 7,870' 7,876' 7,160' 7,166' 6' 07/10/2024 Open
T-100 7,975' 7,995' 7,263' 7,282' 20' 07/10/2024 Open
T-118 8,163' 8,191' 7,448' 7,476' 28' 07/08/2024 Isolated
T142 8,392' 8,412' 8,079’ 8,099’ 20' 06/08/2023 Isolated
T118
T81
T90
T100
T142
T83
5
6
Updated by SRW 07-29-24
PROPOSED
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488’ / TVD = 7,768’
TD = 8,613’ / TVD = 7,892’
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 2,892’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,709’ 8,553’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,717’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.813” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,709’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
5 8,115’ 3.5” CIBP (7/9/24)
6 8,380’ 3.5” CIBP (6/25/24)
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2” TOC @ 2980’ (CBL: 6/6/2023)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
BEL115 ±3,880' ±3,900' ±3,409' ±3,426' ±20' TBD Proposed
BEL115 ±3,904' ±3,914' ±3,429' ±3,437' ±10' TBD Proposed
T2 ±4,282' ±4,370' ±3,744' ±3,817' ±88' TBD Proposed
T5A ±4,558' ±4,618' ±3,974' ±4,025' ±60' TBD Proposed
T6 ±4,707' ±4,779' ±4,101' ±4,164' ±72' TBD Proposed
T6A ±4,791' ±4,801' ±4,174' ±4,183' ±10' TBD Proposed
T7 ±4,882' ±4,939' ±4,254' ±4,304' ±57' TBD Proposed
T19 ±6,170' ±6,200' ±5,485' ±5,515' ±30' TBD Proposed
T45 ±6,730' ±6,740' ±6,037' ±6,047' ±10' TBD Proposed
T65 ±7,321' ±7,358' ±6,619' ±6,656' ±37' TBD Proposed
T-81 7,633' 7,639' 6,926' 6,932' 6' 07/11/2024 Open
T-83 7,696' 7,706' 6,988' 6,998' 10' 07/11/2024 Open
T-90 7,870' 7,876' 7,160' 7,166' 6' 07/10/2024 Open
T-100 7,975' 7,995' 7,263' 7,282' 20' 07/10/2024 Open
T-118 8,163' 8,191' 7,448' 7,476' 28' 07/08/2024 Isolated
T142 8,392' 8,412' 8,079’ 8,099’ 20' 06/08/2023 Isolated
T118
T81
T90
T100
T142
T83
5
6
BEL 115-
T65
Not allowed per calculations on page 2, above. Shallowest
allowable perf is 4,347' MD / 3,798' TVD. SFD
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links
or open attachments unless you recognize the sender and know the content is safe.
From:Scott Warner
To:Davies, Stephen F (OGC)
Cc:McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] Pearl 11 (Permit 223-032, Sundry 324-440) - Question
Date:Tuesday, July 30, 2024 3:49:27 PM
Attachments:image001.png
image002.png
Steve,
Apologies for not including this explanation in the sundry. It is highly unlikely we would be looking to
perforate the T2 and BEL 115 before setting a plug above other perforations below. If we were to set a plug
above the T65, the shallowest allowable perf would then be 3157’ TVD making these depths acceptable.
Hoping to include this in the sundry to get the perforation intervals in the table approved once there is a plug
set above the T65 sand and/or higher. We would not proceed with perforating the T2 and/or BEL 115 without
further communication with the AOGCC showing we have met this requirement.
Thanks,
Scott Warner
Kenai – Operations Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Tuesday, July 30, 2024 3:36 PM
To: Scott Warner <scott.warner@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] Pearl 11 (Permit 223-032, Sundry 324-440) - Question
Scott,
Could you please check and, if needed, correct the following in Hilcorp’s Sundry Application to perforate
additional footage in Pearl 11?
Pearl 11 (Permit 223-032, Sundry 324-440) - Question
Thanks and Be Well,
Steve Davies
AOGCC
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or
privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an
unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in
sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity
named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination,
distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone
if the sender's phone number is listed above, then promptly and permanently delete this message.
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.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 7/30/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240730
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 14B 50133205390200 222057 5/22/2024
YELLOW
JACKET PERF
BCU 14B 50133205390200 222057 6/11/2024
YELLOW
JACKET GPT-PLUG-PERF
BCU 19RD 50133205790100 219188 7/17/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 7/1/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 7/11/2024 AK E-LINE PressureTemp
CLU 16 50133207200000 224021 5/16/2024
YELLOW
JACKET SCBL
CLU 16 50133207200000 224021 5/31/2024
YELLOW
JACKET SCBL
END 2-14 50029216390000 186149 5/9/2024
YELLOW
JACKET PLUG
KU 33-08 50133207180000 224008 5/9/2024
YELLOW
JACKET GPT-PLUG-PERF
MPU H-08B 5.00292E+13 201047 7/14/2024 READ CaliperSurvey
MPU I-40 50029236890000 220071 7/6/2024 AK E-LINE TubingCut
MPU R-101 50029237930000 224078 7/16/2024
YELLOW
JACKET SCBL
MPU S-17 50029231150000 202173 7/12/2024 AK E-LINE TubingCut
MPU S-17 5.00292E+13 202173 7/18/2024 READ CaliperSurvey
PBU NK-43 50029229980000 201001 6/11/2024
YELLOW
JACKET PL
PBU PTM P1-13 50029223720000 193074 7/4/2024
YELLOW
JACKET PL
Pearl 11 50133207120000 223032 7/10/2024 AK E-LINE Plug/Perf
Please include current contact information if different from above.
T39310
T39310T
T39311T
T39312T
T39312
T39313
T39313
T39314
T39315
T39316
T39317
T39318
T39319
T39319
T39320
T39321
T39322Pearl 11 50133207120000 223032 7/10/2024 AK E-LINE Plug/Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.30 13:09:33 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2
Development Exploratory
3. Address: Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 8,613 feet N/A feet
true vertical 7,892 feet N/A feet
Effective Depth measured 8,488 feet 2,708 feet
true vertical 7,768 feet 2,434 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 2,717' MD 2,441' TVD
Packers and SSSV (type, measured and true vertical depth) Swell Pkr; HES TRSV 2,708' MD 2,434' TVD 144' MD/TVD
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
Scott Warner, Operations Engineer
324-125
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
54
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
40
Size
120'
0 44159
0 389
26
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-032
50-133-20712-00-00
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:
ADL0384372 / FEE-PRIVATE
Ninilchik / Beluga-Tyonek
Pearl 11
Plugs
Junk measured
Length
Production
Liner
5,844'
Casing
Structural
7,832'8,553'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
2,892'
7,500psi
2,980psi
6,880psi
8,430psi
2,892' 2,587'
Burst Collapse
1,410psi
4,790psi
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 3:28 pm, Jul 24, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.07.24 15:12:16 -
08'00'
Noel Nocas
(4361)
Page 1/1
Well Name: NINU Pearl 11
Report Printed: 7/17/2024www.peloton.com
Alaska Weekly Report - Operations
Jobs
Actual Start Date:5/14/2024 End Date:
Report Number
1
Report Start Date
5/14/2024
Report End Date
5/14/2024
Last 24hr Summary
Tag bottom @ 8469
Report Number
2
Report Start Date
6/24/2024
Report End Date
6/25/2024
Last 24hr Summary
AKE-line and Baker Hughes PTW and PJSM. RU and M/U SPN (Spectra Pulse Neutron) logging tools. PT 250 psi/2000 psi. RIH and log interval (8380'-1650') at
15-20 fpm. Detected FL at 8090'. Run back in hole and rerun repeat pass over same interval. Detected FL at 8145'. Secure well, rig back E-line.
Report Number
3
Report Start Date
6/25/2024
Report End Date
6/26/2024
Last 24hr Summary
AK E-line and Fox N2 PTW and PJSM. RU E-line M/U GPT, RIH and locate fluid level at 8400' (T-142 8392'-8412'). M/U setting tool and 3.50" CIBP. RIH, tie-in and
set plug at 8380'. RD E-line and RU Fox N2 PT 250 psi / 2500 psi. Pump and trap 2060 psi of N2 on tubing. RD Fox Energy.
Report Number
4
Report Start Date
7/8/2024
Report End Date
7/9/2024
Last 24hr Summary
PTW/PJSM. MIRU AK E-line. P-test 250/3000 psi. Perforate T-118 Sand from 8,163' - 8,191'. Init SITP 2007 psi, 15 min 2009 psi. Bleed well down - detected 100%
LEL's when FTP was at ~300 psi. Put well into test but no measurable flow. Run GPT - fluid level at 8,050'. SDFN.
Report Number
5
Report Start Date
7/9/2024
Report End Date
7/10/2024
Last 24hr Summary
PTW/PJSM. SITP 736 psi. AK E-line pick-up lub and tools. Run GPT - fluid level at 7,820'. Push fluid down to 8,170' with 162.8 mscf nitrogen. Shut down with 3,710
psi SITP. Set CIBP at 8,115'. SITP 2,880 psi. SDFN.
Report Number
6
Report Start Date
7/10/2024
Report End Date
7/11/2024
Last 24hr Summary
PTW/PJSM. SITP 2,460 psi. AK E-line pick-up lub and tools. Bleed well pressure down to 1,520 psi. Perforate T-100 Sand from 7,975' - 7,995'. Init SITP 1,520 psi.
15 min SITP 1,519 psi. Run GPT and tagged plug @ 8115' with No fluid. Pressure up well to 1200 psi with N2. Perforate T090 sands from 7870'-7876'. Flow
well. No gas to sustain flow. SDFN.
Report Number
7
Report Start Date
7/11/2024
Report End Date
7/12/2024
Last 24hr Summary
RIH with GPT and fluid sample catcher. Tool shorted out at 1700'. POOH. Troubleshoot short. RIH with same BHA. Tagged plug at 8,115'. Fluid level at 7925'
with 122 psi WHP. GPT tool shorted out again while POOH. Diagnoise at surface. Trim 300' of E-line cable. Make up gun RIH and perforate the T-83 sands
from 7696'-7706', wkth 1500 psi of N2 on well. Gun is dry. Flow to production with no sustained flow. MU GPT. Found fluid level 7888' . Continue to perforate the T
-81 sands with 1500 psi N2 from 7633'-7639' with 800 psi SITP. POOH. Full rig dow of AK E-line.
Field: Ninilchik
Sundry #: 324-125
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-032Permit to Drill (PTD) #:223-032
Wellbore API/UWI:50-133-20712-00-00
Updated by DMA 07-17-24
SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488 / TVD = 7,768
TD = 8,613 / TVD = 7,892
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 2,892
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958 2,709 8,553
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958 Surf 2,717
4
16
7-5/8
9-7/8
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 144 3.813 5.500 SSSV
2 1,524 3.958 4.500 Chemical Injection Sub
3 2,709 4.875 6.540 Liner hanger / LTP Assembly
4 2,717 4.790 6.340 Seal Stem
5 8,115 3.5 CIBP (7/9/24)
6 8,380 3.5 CIBP (6/25/24)
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2 TOC @ 2980 (CBL: 6/6/2023)
6-3/4
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T-81 7,633' 7,639' 6,926' 6,932' 6' 07/11/2024 Open
T-83 7,696' 7,706' 6,988' 6,998' 10' 07/11/2024 Open
T-90 7,870' 7,876' 7,160' 7,166' 6' 07/10/2024 Open
T-100 7,975' 7,995' 7,263' 7,282' 20' 07/10/2024 Open
T-118 8,163' 8,191' 7,448' 7,476' 28' 07/08/2024 Isolated
T142 8,392' 8,412' 8,079 8,099 20' 06/08/2023 Isolated
T118
T81
T190
T100
T142
T83
5
6
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 7/11/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240711
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 6/28/2024 AK E-LINE Perf
BRU 214-13 50283201870000 222117 7/2/2024 AK E-LINE Perf
IRU 44-36 50283200890000 193022 6/28/2024 AK E-LINE TubingCut
Pearl 11 50133207120000 223032 6/25/2024 AK E-LINE GPT/Plug
Pearl 11 50133207120000 223032 7/8/2024 AK E-LINE Perf
SRU 13-09 50133203430000 181098 6/9/2024 AK E-LINE CBL/CIBP/PUNCH
Revision Explanation: There are additional images added to the final report and a few new .las
files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and
POOH are new .las files
Please include current contact information if different from above.
T39171
T39172
T39173
T39174
T39174
T39175
Pearl 11 50133207120000 223032 6/25/2024 AK E-LINE GPT/Plug
Pearl 11 50133207120000 223032 7/8/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.11 13:30:29 -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: Install Cap String, N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
8,613'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 Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
scott.warner@hilcorp.com
907-564-4506
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Scott Warner, Operations Engineer
AOGCC USE ONLY
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):
Subsequent Form Required:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0384372 / FEE-PRIVATE
223-032
50-133-20712-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L--80
TVD Burst
2,717'
8,430psi
2,587'
Size
120'
2,892'
MD
See Schematic
2,980psi
6,880psi
120'120'
2,892'
March 12, 2024
Tieback 4-1/2"
8,553'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Pearl 11CO 701H
Same
7,832'4-1/2"
~2754psi
5,844'
N/A
Length
Swell Pkr; HES TRSV 2,708' MD/2,434' TVD;144' MD/TVD
7,892'8,488'7,768'
Ninilchik Beluga-Tyonek Gas
16"
7-5/8"
See Schematic
P
s
66
2
c
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 12:58 pm, Mar 01, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.02.29 17:16:11 -
09'00'
Noel Nocas
(4361)
324-125
Perforate
BJM 3/4/24
10-404
SFD 3/4/2024 DSR-3/4/24*&:
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.03.05 09:26:54 -09'00'03/05/24
RBDMS JSB 030524
Well Prognosis
Well: Pearl 11
Date: 2/27/24
Well Name: Pearl 11 API Number: 50-133-20712-00-00
Current Status: Producing Gas Well Permit to Drill Number: 223-032
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: 3564 psi @ 8099’ TVD Based on 0.44 psi/ft
Max. Potential Surface Pressure:2754 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: .75 psi/ft using 14.6 ppg EMW FIT at the surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.75-0.1) = 2754 psi / 0.65 = 4237‘ TVD
Top of Applicable Gas Pool: 1680’ MD/ 1581’ TVD
Well Status: Online Gas Producer flowing at 440 mcfd, 9 bwpd, 57 psi FTP
Brief Well Summary
Pearl 11 is a grass roots well drilled in 2023 targeting the Beluga and Tyonek sands in the southernmost portion
of the Ninilchik Unit. Initial perforations were added in the T-142 and came on strong at 9 mmscfd but has
been on steady decline since.
The purpose of this sundry is to perforate additional footage in the Tyonek 81-118 sand to increase production.
Notes Regarding Wellbore Condition
06/08/2023 Perforated T-142 sand from: 8392’-8412’ with 2-3/4” guns
09/21/23 D&T w/ 2.5” DD bailer. Tag fluid @ 8390’S SLM. Tag TD @ 8484’ SLM.
Procedure:
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250 psi low / 3,000 psi high
3. PU GPT and RIH to confirm fluid depth
4. RIH and perforate Tyonek 81- 118 sands from bottom up with 2-3/4” 60 deg phased perf guns:
Below are proposed targeted sands in order of testing (bottom/up),
but additional sand may be added depending on results of these
perfs, between the proposed top and bottom perfs
Sand Top MD Btm MD Top TVD Btm TVD Interval
T-81 ±7,633' ±7,639' ±6,926' ±6,932' ±6'
T-81 ±7,648' ±7,653' ±6,941' ±6,946' ±5'
T-83 ±7,696' ±7,707' ±6,988' ±6,999' ±11'
T-90 ±7,855' ±7,862' ±7,145' ±7,152' ±7'
T-90 ±7,870' ±7,875' ±7,160' ±7,165' ±5'
T-100 ±7,975' ±7,993' ±7,263' ±7,280' ±18'
T-118 ±8,163' ±8,191' ±7,448' ±7,476' ±28'
a. Proposed perfs are also shown on the proposed schematic in red font
1680’ MD/ 1581’ TVDTop of Applicable Gas Pool:
Well Prognosis
Well: Pearl 11
Date: 2/27/24
b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to
the Operations Engineer, Reservoir Engineer, and Geologist for confirmation
c. Use Gamma/CCL to correlate
d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min
intervals post perf shot (if using switched guns, wait 10 min between shots)
e. Pending well production, all perf intervals may not be completed
f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
setting a plug above perforations
5. RDMO
a. If necessary, run cap string to aid with water production if encountered post perforating
i. RU Cap String Truck
ii. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components.
Install pack-off and pressure test against swab valve to 2500 psi
iii. RIH with 3/8” capillary string to ±8300’ MD
a. Set cap string as deep as practical in fluid
iv. Install slips and connect tubing to chemical injection pump
v. Set spool of remaining line near well
vi. RD cap string Unit, and turn well over to production
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Standard Well Procedure – N2 Operations
Updated by CJD 06-21-23
SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488’ / TVD = 7,768’
TD = 8,613’ / TVD = 7,892’
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 2,892’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,709’ 8,553’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,717’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.613” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,709’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2” TOC @ 2980’ (CBL: 6/6/2023)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T142 8,392' 8,412' 8,079’ 8,099’ 20' 06/08/2023 Open
T142
Updated by SRW 02-26-24
Proposed
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488’ / TVD = 7,768’
TD = 8,613’ / TVD = 7,892’
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 2,892’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,709’ 8,553’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,717’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.613” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,709’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2” TOC @ 2980’ (CBL: 6/6/2023)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T-81 ±7,633' ±7,639' ±6,926' ±6,932' ±6' Proposed TBD
T-81 ±7,648' ±7,653' ±6,941' ±6,946' ±5' Proposed TBD
T-83 ±7,696' ±7,707' ±6,988' ±6,999' ±11' Proposed TBD
T-90 ±7,855' ±7,862' ±7,145' ±7,152' ±7' Proposed TBD
T-90 ±7,870' ±7,875' ±7,160' ±7,165' ±5' Proposed TBD
T-100 ±7,975' ±7,993' ±7,263' ±7,280' ±18' Proposed TBD
T-118 ±8,163' ±8,191' ±7,448' ±7,476' ±28' Proposed TBD
T142 8,392' 8,412' 8,079’ 8,099’ 20' 06/08/2023 Open
T142
T81-T118
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.
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: 07/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
Radial Cement Bond Log (06/06/2023)
Folder Contents:
Please include current contact information if different from above.
PTD: 223-032
T37879
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.07.26
08:49:20 -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
T37817Pearl 11 50133207120000 223032 6/8/2023 AK E-LINE Perf
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.10
13:32:37 -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: 122.3' 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 2,587'
4-1/2" L-80 7,832'
4-1/2" L-80 2,442'
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
4-1/2" Tieback
SIZE DEPTH SET (MD)
2,709' MD / 2,441' TVD
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,709' 8,553'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy.Tieback
TUBING RECORD
L- 533 sx / T - 98 sx6-3/4"
2,717'
9-7/8"
Driven
Surface L - 360 sx / T - 173 sx
12.6#
Surface
Surface
2,892'
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
203202 2225823
50-133-20712-00-00May 1, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
6/8/2023 223-032 / 323-301
LOCI 17-001
Pearl 11May 11, 2023324' FNL, 714' FEL, Sec 23, T1S, R14W, SM, AK
140.3'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2228725
SETTING DEPTH TVD
2228755
TOP HOLE SIZE
CBL 6-7-23, Mudlog, LWD (DGR, EWR-P4, PWD, DDSR, ALD, CTN)
Beluga-Tyonek Gas Pool
Private / ADL 384372
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
203137
203126
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
N/A
N/A
144' MD / 144' TVD
8,613' MD / 7,892' TVD
8,488' MD / 7,768' TVD
2625' FNL, 867' FEL, Sec 14, T1S, R14W, SM, AK
2596' FNL, 879' FEL, Sec 14, T1S, R14W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
2,717'
2,441'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
6/9/2023
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
002196 485
6/17/2023 24
Flow Tubing
0
5027
N/A50270
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 8:15 am, Jun 22, 2023
Completed
6/8/2023
JSB
RBDMS JSB 062223
GDSR-6/28/23
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval T 142 8,392' 8,079'
903' 892'
1321' 1278'
4239' 3708'
4247' 3715'
4327' 3782'
4860' 4235'
5654' 4978'
6838' 6144'
7833' 7123'
8246' 7530'
8279' 7563'
8369' 7651'
8553' 7832'
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.
Ty 90
Tyonek
ST 2
Ty 2
Ty 50
Bel C
Bel 136
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
INSTRUCTIONS
Ty 145
Ty 7
Ty 14
Ty 120
Ty 140
Ty 142
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
6.21.2023
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: 2023.06.21 15:07:36 -08'00'
Monty M
Myers
Updated by CJD 06-21-23
SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,488’ / TVD = 7,768’
TD = 8,613’ / TVD = 7,892’
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 2,892’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,709’ 8,553’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,717’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.613” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,709’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (62 bbls lead to surface)
4-1/2” TOC @ 2980’ (CBL: 6/6/2023)
6-3/4”
hole
3
2
1
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
T142 8,392' 8,412' 8,079’ 8,099’ 20' 06/08/2023 Open
T142
Activity Date Ops Summary
4/29/2023 B/D and disconnect steam, water & air lines from all modules. Continue disconnecting all interconnects. R/D Top Drive HPU and Grasshopper (Electrical) going
to back yard. Remove torque tube bushing from floor, Set Top Drive in cradle and lower to catwalk. Connect bridle lines to Blocks.;Remove clam shell and all pit
windwalls. Remove Centrifuge. Bed truck remove Cement silo, Upright water tank, Boiler house, Mud Pump #2, Mud Pump #1, Loader grab Jig. Bed truck
remove all three pit modules, Top Drive HPU and Generator module. Transfer BOP stack into cradle and secure.;Scope down derrick to half mast. Install
shipping beams under sub. Layover V-Door on catwalk and move catwalk. Prep and lay over derrick. Remove Choke House and windwall from floor with crane.
Lower doghouse into water tank. Spot cranes, Prep and remove derrick from draworks skid,;Remove drum of drill line and place on trailer with derrick. Prep and
remove draworks skid from subbase.;Crane off sub and move pony subs, Spot pony subs over well and center, lay felt and seam in herculite, lay mats, spot
cranes and set sub, set draw works and derrick on sub, spot in pit modules and dog house, set mud pumps and top drive HPU, set gen skid, raise derrick, set in
boiler house;Spot in catwalk and raise ramp, hook up electrical and power up rig, and hydraulics, hook up steam air and water lines, prep to scope derrick, hook
up pason and rig camera systems
4/30/2023 Install drive line and brake linkage. Spool up drilling line on draworks, Rig up Gen 3, Prep and Telescope Mast. Install Lower torque tube, Turnbuckles and T-
Bar. Inspect Eaton Brake on Draworks. R/U Fire and Gas alarms. Install wind wall on rig floor and all wind walls on pits. Raise Gas Buster.;Install Wear Ring and
running tool in starting head and RILDS. Start N/U 16" x 21-1/4" DSA & Tee for diverter. Complete installation of Handy Berm. Submitted 24 hour Notification to
AOGCC for Diverter Test @ 08:17 AM for 09:00 AM tomorrow. Connect all third party shacks.;Continue N/U DSA, Tee Spool, 21-1/4" Annular, Bell Nipple, Flow
Line and Vent Line with Anchors. Complete Eaton Brake inspection. P/U Top Drive in carrier and set on rig floor, Attach Top Drive to Blocks and connect service
loop. Check end play on quill. Install Torque Bushing.;Install bails and elevators, hang rig tongs and get all equipment to floor, work on rig acceptance check list,
run water through pits and check function, function test centrifugal pumps on mud tanks, function iron roughneck. Accept Rig @ 0000 hrs;Rack and tally DP, P/U
and rack back DP in derrick, Mix spud mud in pits, move diverter vent line so it points further away from ocean.
5/1/2023 Re-Assemble vent line. Finish staging up boilers and circulate steam through rig. Continue To P/U, M/U and stand back 57 stands Drill Pipe, 8 stands HWDP,
Jar stand and Flex Collar stand. Complete 300 BBLs of spud mud. Repair equalizer line in mud pits. Fabricate new flowline. Function test;all PVT system.
Quadco calibrate and test gas alarm system. Function test Mud Pumps #1 & #2. Fill surface lines and pressure test T/ 2000psi. Good Test. Fill hole with fluid.
Recharge thread compensator cylinders on Top Drive. Install Mouse Hole Function Test Annular and Knife Valve.;PJSM, Prep Rig floor and catwalk for BHA.
M/U 9-7/8" Kymera Bit previously used at Paxton 12 (48K revs currently) to mud motor, Stabilizer, Crossover sub and RIH W/ BHA and tagged at 128' washed
down T/ 135';Spud well and drill 9-7/8" Section F/ 135' T/ 165'. GPM 400 SPP 550psi. RPM 30 TQ 2.1K;POOH F/ 135' T/ 41' standing back 2 stands of HWDP.
PJSM M/U Directional BHA #1 and program tools (Download). RIH and shallow test. Good. POOH, PJSM and load sources.;Continue drilling 9-7/8" surface
section F/ 165' T/ 689' 450 gpm 1337 psi 46 RPM 2.5k tq on bottom 6k WOB, MW 8.95 ppg ECD 9.49 ppg, PUW 42k SOW 42k ROT 42k;Continue Drilling 9
7/8'' Surface Section f/ 689' t/ 1038' 450 gpm 1450 psi 55 RPM 3.4k tq on bottom, 8k WOB, 8.9 ppg MW 9.39 ppg ECD 49k PUW 46k SOW 45k ROT Distance f/
Plan 17.28' 6.93' High 15.83' Left
5/2/2023 Continue Drilling 9 7/8'' Surface from 1038' to 1370'. Rot wob 8K, 506 gpm-1839 psi, 50 rpm-3500 ft/lbs on bott torque, 111 ft/hr ROP. Sliding wob 17K, 484 gpm-
1800 psi, 240 psi diff, 150 ft/hr ROP. MW 8.9/vis 121, ECD's at 9.3+, BGG 26 units.;Continue drilling from 1370' to 1493'. Rot wob 11K, 506 gpm-1921 psi, 55
rpm-4800 ft/lbs on bott torque, 100 ft/hr ROP. Sliding wob 19K, 506 gpm-1900 psi, 209 psi diff, 90 to 160 ft/hr ROP. MW 8.9+/vis 201, ECD's at 9.9.5+. BGG 18
units. Mad passed slide intervals.;CBU for wiper trip at 506 gpm-1769 psi, 55 rpm-3200 ft/lbs off bott torque. Obtained on bottom survey and flow check =
static.;Pulled up hole on elevators from 1490', up wt 62K. Pulled to jars then parked string at 384'. Calculated hole fill = 13.1 bbls, actual hole fill = 14.8
bbls.;Serviced rig and topdrive, tightened up torque tube turn buckles. Rig electrician repaired electrical junction box on shaker #2, cleaned screens on both
mudpumps.;TIH slow from 384' to 1430' with no issue, MU topdrive on last stand and filled pipe, washed to bottom. Calculated displacement = 18.4 bbls, actual
displacement = 19.2 bbls.;Resumed drilling surface hole from 1493' to 1930' 505 gpm 2015 psi 60 rpm 5.5k tq on bottom, 10k WOB, MW 9.0 ppg ECD 9.62 ppg,
66k PUW 50k SOW 60k ROT;Continue Drilling 9 7/8'' Surface hole f/ 1930' t/ 2299' 503 gpm 2100 psi SPP 60 rpm 5800 tq on bottom MW 9.15 ppg ECD 9.79
ppg PUW 69k SOW 58k ROT 60k, Max Gas 74 units Distance to plan 14.60' 5.87' Low 13.37' Right;Change Swivel Packing on top drive
5/3/2023 Cont drilling surface from 2299' to 2641'. Rot wob 9 to 14K,506 gpm-2164 psi, 60 rpm-5800 to 6100 ft/lbs on bott torque, 70 to 90 ft/hr ROP. Sliding wob 13K,
506 gpm-2250 psi, 250 psi diff, 80 ft/hr ROP. MW 9.2+/vis 161, ECD's at 9.8, BGG 32 units.;Cont drilling to TD at 2898' md/2592' tvd. Rot wob 15K, 552 gpm-
2514 psi, 65 rpm-6364 ft/lbs on bott torque, 70 to 100 ft/hr ROP. MW 9.4/vis 72, ECD's at 9.8, BGG 20 units, max gas 41 units. Sent AOGCC 24 hr notice of
upcoming casing run and cementing.;CBU at 553 gpm-2381 psi, 60 rpm-5000 ft/lbs off bott torque. TD'd in claystone, sand and a bit of carbonaceous material.
Obtained on bottom survey and flow check = static.;Pulled up hole on elevators from 2898' to HWDP at 695', up wt 85K. Calculated hole fill = 17.1 bbls, actual
hole fill = 20.8 bbls.;Service rig and topdrive.;TIH on elevators from 695' to 2898' wash last stand to bottom no fill, Act Disp 43.3 calculated 43.9.;Circulate Hi Vis
Sweep Around 100% increase in cuttings on bottoms up 10% Increase in cuttings when sweep came back sweep was on time flow check well Static.;POOH f/
2898' t/ Surface, Unload sources, Download MWD, L/D BHA as per MWD/DD Break bit Graded 1-1-WT-A-X-1-WT-TD / 1-1-WT-A-E-1-WT-TD, Clear Floor.;Spot
in and R/U Halliburton ELine P/U tool String, Hang Sheave, Make up Sonic Tool String - 71.29' OAL RIH, On Bottom 2896' WLM 0450 hrs, Log Out of Hole 30
FPM to Surface.
18
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
NINU Pearl 11
Ninilchik
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00056 Pearl 11 Drilling
Spud Date:
5/4/2023 Cont log 9 7/8" open hole with e-line OOH and into conductor, pulled to surface, cleaned and LD tool string, RD and released Halliburton e-line.;Staged cleanout
BHA on catwalk, PU and MU 9 7/8" tri-cone, bit sub with float, IBS, RIH with NM flex DC's, HWDP and jars for total BHA length of 635.67'.;TIH on DP from 635'
to 1558', MU topdrive, filled pipe then CBU 1 time to condition spud mud. Cont TIH to 2860', MU topdrive on last stand, filled pipe, pumped a 20 bbl hi-vis
nutplug sweep as we washed to bottom at 2898'. No issue during trip.;Calculated displacement = 55.7 bbls, actual displacement = 54.4 bbls. Sent AOGCC 24 hr
notice for upcoming initial BOP test at 10:13. Witness of BOP test was waived by Jim Regg at 10:16.;Increased pump rate to 504 gpm-1303 psi, 65 rpm-5000
ft/lbs off bottom torque and circulated sweep around. Had no increase in cuttings at bottoms up, 25% increase with sweep to surface. Sweep back on time. Cont
to circ until 9.4 ppg in/out, racked one stand back and flow check = slight seepage.;POOH from 2856' to BHA at 635'.;Racked back HWDP, LD jars, NM flex
DC's, IBS, bit sub and bit. Bit graded a 1-1, calculated hole fill = 24.1 bbls, actual hole fill = 26.8 bbls.;Cleared and cleaned rig floor, removed all subs no longer
needed, PU test joint with run tool, retrieved wear ring, PU landing joint with hanger and dummy ran same. Staged casing tong power pack, staged casing tools
on walk.;RU fill up line, staged centralizers and drive sub, swapped out elevators, RU casing tongs, held PJSM with rig team and casing crew.;PU and MU 7 5/8"
shoe track, BakerLock'd each joint, top filled each joint, checked that float equipment functioned properly (OK), cont PU single in hole with 7 5/8" 29.7# L-80
CDC casing, torqued to 15,500 ft/lbs, top filling on the fly, topping off every 10 jnts from 123' to 2892'.;Tag bottom @ 2898' M/U Hanger and landing jt, PUW
105k SOW 68k.;Circulate and condition mud for cement Job, stage pumps t/ 6 bpm 132 psi, R/D Casing equipment, SPot in and R/U cementers, Load plugs,
Hold PJSM with all crew involved.;M/U cement head and cement lines, blow down top drive.;Halliburton Pumped 5 bbls water to fill lines, PT lines to 309 psi Low
3519 psi High good test, pumped 60 bbls 10.5 ppg tuned spacer at 5 bpm 150 psi to 145 psi, dropped bottom plug and pumped 154 bbls (360 sx) 12 ppg Lead
Type I II Cement at 5 bpm 100 psi, followed by 31.5 bbls (173 sx);Tail Type I II Cement 15.8ppg Dropped top Plug and began displacing w/ 9.4 ppg spud mud.
5/5/2023 Cont displacing with 9.4 ppg spud mud and bumped plug 125.5 bbls into displacement (calculated at 129 bbls). Held 1345 psi for 3 minutes, bled off and floats
held. Bled back 1/2 bbl to truck. Had 60 bbls of spacer returns to surface and 62 bbls lead cement to surface. Added Bridge Maker;LCM to lead cement at 2.4
pps. Mix water temp 67 deg. Pumped 50% excess. No losses throughout the job. Reciprocated casing twice a minute, CIP at 06:30 on 5-5-23. Broke off and
blew down cement line to truck.;RD cement head and buddy bails, drained stack, BO landing joint and drained same, rinsed out and L/D landing joint, flushed
stack with black water through fill up line twice, MU diffuser on jnt 4 1/2" DP, flushed stack with black water through topdrive. Broke off diffuser, MU packoff run
tool and;packoff, set pack off and RILD's. Tore out diverter vent line and anchors, Quadco Rep on location at 09:30 and calibrated/tested all audio/visual gas
alarms. Verified "B" section orientation with pad operator. Wellhead Rep tested packoff seals at 3000 psi for 15 minutes, good test.;Removed 4 way chains, RD
flowline and riser, tore out remainder of vent line and knife valve, removed annular from cellar.;Removed diverter T and DSA, brought in wellhead "B" section,
RU and stabbed same, removed shipping beams, folded over beaver slide, staged crane and BOP cradle, transferred BOP stack from cradle to bridge cranes in
cellar while MU 16 3/4" 3M x 11" 5M "B" section on wellhead,;re-set beaver slide. Installed choke HCR on mud cross while removing lower torque tube from
derrick. Wellhead Rep tested flange and HPS seals to 3000 psi for 15 minutes, good test. Stab and NU BOP stack, replaced torque tube section and staged on
catwalk for PU, installed choke/kill lines,;installed drip pan, riser and flow line, chained off stack, installed koomey lines. Built 360 bbls 6% KCL mud. At 15:00
hrs rig loader was backing away from hopper area mud dock and back of loader made;contact with dragon wagon trailer as driver was passing by. Landing gear
handle was damaged on trailer of dragon wagon, no damage to actual tank. Loader radiator fan cover was damaged but repairable, Notified Hilcorp/Parker HSE
Reps and Drilling Engineer.;Function tested BOPE, MU test plug on 4 1/2" test jnt and set same, flooded stack and surface equipment with water. Shell tested
BOPE.;Re-hung lower half of torque tube and secured to "T" bar.;Tested BOP's t/ 250/3500 psi f/ 5 min each test annular t/ 250/2500 psi f/ 5 min with 4.5'' test jt.
Had one fail pass Auto IBOP failed low and high test, replaced and retested good, Perform Draw down accumulator test.;Pull test plug set wear ring, flood lines
and stack.;R/U and test casing to 3500 psi f/ 30 min pumped 1.64 bbls in bled back 1.4 bbls.;R/D test equipment blow down lines and choke manifold, clear
floor.;Rack and tally 114 jts of DP, RIH w/ 4.5'' DP t/ 1085'.
5/6/2023 Cont PU single in hole with 4 1/2" DP from 1085' to 1862'. Ran total 60 jnts in hole.;POOH racking back in derrick 30 stands DP from 1862' to surface.;PU single
in hole with 54 jnts 4 1/2" DP to 1673'.;POOH racking back in derrick 27 stands DP from 1673' to surface.;Serviced rig and topdrive, staged BHA at catwalk
along with more DP.;PU 4 3/4" motor with 1.5 bend, MU HDBS 6 3/4" GTD54DM PDC, MU DM and SP4 collars, scribed with an RFO of 202.50, MU ALD, CTN,
PWD and TM collars, plugged in and uploaded MWD, shallow pulse tested, held PJSM and loaded sources, PU NM flex DC's, HWDP and jars to 726'.;PU
singled in hole with 64 joints 4 1/2" DP from 726' to 2763', MU topdrive on last stand.;Filled pipe, washed down at 207 gpm-1091 psi, 30 rpm-4393 ft/lbs off bott
torque and tagged top of wiper plugs on depth at 2808'. Drilled up wiper plugs, float collar, 80' shoe track, shoe at 2892', 6' rathole cement to 2898'. 2-5k
WOB.;Drilled 20' new formation from 2898' to 2918'. Rot wob 6 to 9K, 202 gpm-1213 psi, 30 rpm-4400 ft/lbs on bott torque, 35 to 60 ft/hr ROP.;CBU and held
PJSM on displacing to 6% KCL mud, pumped 20 bbl hi-vis spacer pill followed with 9.3 ppg 6% KCL mud, 202 gpm-908 psi, 30 rpm-4357 ft/lbs off bott
torque.;RU test equipment, performed FIT to EMW of 14.6 ppg with 715 psi, RD test equipment.;Drill 6 3/4'' Hole Section f/ 2918' t/ 3447' 275 gpm 1745 psi SPP
65 RPM 5.3k tq on bottom, 5k WOB, PUW 84k SOW 58k ROT 67k, MW 9.3 ppg ECD 10.5, Distance to Plan 4.46' .03' Low 4.46' Right.
5/7/2023 Cont drilling 6 3/4" hole from 3447' to 3933', Rot wob 4K, 275 gpm-1831 psi, 80 rpm-5900 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob4K, 276 gpm-1870 psi,
245 psi diff, 113 ft/hr ROP. MW 9.4/vis 59, ECD's at 11.3 ppg, BGG 16 units, max gas 241 units.;CBU at 276 gpm-1700 psi, 83 rpm-5400 ft/lbs off bott torque.
After bottoms up obtained on bottom survey and SPR's. Flow check was static.;Pulled up hole on elevators from 3933' to 2947', up wt 98K. Had to work through
four tight spots after pulling 25K over at each: 3337', 3308', 3280' and 3155'. All siltstone/silty sandstone. Calc hole fill = 7.4 bbls, actual hole fill = 7.7
bbls.;Serviced rig and topdrive, checked torque tube bolts (tight), cleaned suction and discharge screens on mud pumps. Well on trip tank during rig service
showing .96 bph loss rate.;RIH on elevators from 2947' to 3874' with no issue, MU topdrive on last stand, filled pipe, washed/reamed to bottom at 3933', made
hook. Calculated displacement = 18.3 bbls, actual displacement = 17.7 bbls.;Pumped a 20 bbl hi-vis nutplug sweep, once sweep exited the bit, resumed drilling
ahead. 500 strokes into initial bottoms up (1800 stks) gas increased to a max of 1309 units gas. Sweep was back on time with a 25% increase in fine silt and
clay. Drilled from 3933' to 4119', Rot wob 3-5K,;285 gpm-1912 psi, 83 rpm-6100 ft/lbs on bottom torque,120 ft/hr ROP. Sliding wob 6K, 278 gpm-1930 psi, 283
psi diff, 126 ft/hr ROP. MW 9.4/vis 52, ECD's at 11.0 ppg, BGG 19 units, max gas 149 units. No connection gas.;Cont drilling 6 3/4" hole from 4119' to 4584',
281 gpm 1872 psi SPP 82 rpm 6.6k tq on bottom, max gas seen 336 units MW 9.4 ppg ECD 11.08 PPG, 103K PUW 66k SOW 82k ROT.;Cont Drilling 6 3/4''
Hole Section f/ 4584' t/ 4965' 274 gpm 1930 psi 80 rpm 7.1k tq on bottom MW 9.5ppg ECD 10.99 ppg PUW 108k SOW 67k ROT 84k, Max Gas 280 units
Distance to Plan 4.05' 1.98' Low 3.54' Left.
5/8/2023 At 4987' CBU at 275 gpm-1737 psi, 80 rpm-7240 ft/lbs off bott torque. Obtained SPR's then flow checked = static.;Pulled up hole on elevators from 4987' to
3918' then parked string at 3980'. Up wt coming off bottom 125K. Had 20K over pull at 4370' (claystone/siltstone) and 20K overpull at 3950'
(claystone/mudstone) Worked through both on elevators. Calculated hole fill = 6.9 bbls, actual hole fill = 6.9 bbls.;Serviced rig and topdrive. Well on trip tank and
taking .80 bph.;TIH on elevators from 3980' to 4924' with no issue. MU topdrive on last stand, filled pipe and washed to bottom. Calculated displacement = 18.3
bbls, actual displacement = 17.7 bbls. Started a 20 bbl hi-s nutplug sweep around.;Circulated sweep around at 275 gpm-1711 psi, 80 rpm-8000 ft/lbs off bott
torque and reciprocated string. At bottoms up we had a max of 534 units gas, 25% increase in cuttings. Sweep was back on time with a 50% increase in
cuttings.;Cont drilling 6 3/4" hole from 4987' to 5052'. Sliding wob 2 to 4K, 287 gpm-1937 psi, 240 psi diff, 130 ft/hr ROP. Rot wob 5K, 276 gpm-1838 psi, 80 rpm-
7200 ft/lbs on bott torque, 100 ft/hr ROP. MW 9.4+/vis 51, ECD's at 10.8 ppg, BGG 8 units, max gas 82 units.;Cont drilling 6 3/4" hole from 5052' to 5478', rot
wob 3 to 5K, 287 gpm-1996 psi, 60 rpm-7070 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5 to 6K, 288 gpm-2127 psi, 286 psi diff, 160 ft/hr ROP. MW 9.4/vis
57, ECD's at 11,2 ppg, BGG 31 units, max gas 313 units. After making connection at;5230' md/4571' tvd, mud loggers saw connection gas of 2 units there, and
over the next 4 connections of 16-22-15-15 units. Did flow check prior to connection at 5478'/4808' tvd and had a tapering off flow like well was breathing back.
Start dusting MW to 9.5 ppg.;Cont drilling 6 3/4" hole from 5478' to 5853' 276 gpm 2153 psi SPP 60 RPM 8k tq on bottom, 6k WOB, MW 9.5 ppg ECD
11.41ppg, PUW 114k SOW 80k ROT 95k Max Gas 178 units.;Cont Drilling 6 3/4'' Hole Section f/ 5853' t/ 5975' 276 gpm 2200 psi 60 rpm 8.5k tq on bottom, 6k
WOB MW 9.5 ppg ECD 11.52ppg, PUW 124k SOW 80k ROT 99k Max Gas 304 Units Distance to Plan 7.67' 5.07' Above 5.75' Left.;CBU, Obtain Survey and
SPR's Flow check well slight flow slowing to static in 25 min, Blow Down top drive.;Make wiper trip f/ 5975' to 2888' wiped through numerous 10-20k over pulls
from 3985' t/ Shoe, kelly up and washed through tight spot @ 3669' Act 22.5 Calc 20.7 Diff 1.8 Gain.
5/9/2023 With string parked at 2888, serviced rig and topdrive with hole on trip tank. 0.27 bph loss rate during service. Cleaned pump screens, adjusted omni wrap on
kelly hose, changed oil on floor motor.;TIH slow on elevators getting decent displacement to 3812'. TIH to 4727' getting less displacement (4 bbls under calc).
MU topdrive and filled pipe.;Circulated surf to surf at 120 gpm-832 psi, up wt 107K, dwn wt 70K. Had a max of 618 units early (from Beluga 110 at 3900) then
121 units at actual bottoms up. Ran centrifuge to reduce the 9.8 ppg return mud. Gas dwn to 39 units. MW at 9.6 in/9.7 out at shut down.;Cont TIH slow, dwn wt
65K, with much better displacement from 4727' to 5908, MU topdrive, filled pipe, washed/reamed to bottom at 5975', 265 gpm-1990 psi, 45 rpm-8200 ft/lbs off
bott torque, started a 20 bbl hi-vis nutplug sweep.;1685 strokes into bottoms up (2696 stks) gas increased to 1752 units and hole unloaded significantly. Gas
dropped off to 9 units at bottoms up with no increase in cuttings. Sweep back on time and had an additional 25% increase in fine silt/clay. With 9.6 ppg in/out got
SPRs and made hook.;Cont drilling 6 3/4" hole from 5975' to 6346', rot wob 3-4K,276 gpm-2037 psi, 65 rpm-9063 ft/lbs on bott torque, 11 to 120 ft/hr ROP.
Sliding wob 3 to 6K, 276 gpm-2003 psi, 200 psi diff, 95 ft/hr ROP. MW 9.6/vis 54, ECD's 10.9 ppg, BGG 18 units, max gas 307 psi. No connection gas.;Cont.
drilling 6-3/4" hole F/6346'-T/6469'. P/U-142K S/O-84K ROT-106K GPM-276 SPP-2153 psi RPM-60 TQ-9.3K WOB-5/7K DIFF-282 psi MW-9.6 ppg ECD-11.02
ppg Max gas-440 units. Obtained new SPR's @ 6469'.;Pumped tandem sweep - 20 bbl Low Vis/ Low weight - 38 Vis/9.1 ppg followed by 20 bbl Hi-Vis/ Hi weight
300 Vis/ 10.6 ppg w/ walnut & condet in both. Sweeps came back on time w/ a 20% increase in cuttings.;Resumed directional drilling 6-3/4" production hole
F/6469'-T/6629'. P/U-150K S/O-85K ROT-108K GPM-276 SPP-2094 psi RPM-60 TQ-9.3K WOB-5/7K DIFF-137 psi MW-9.65 ppg ECD-10.96 ppg Max gas-357
units.;Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/6629'-T/6722'. Started seeing connection gas. Flow checked well due to 2%
increase in flow. Flow checked well for 5 min = .8 bph flow. Bumped MW from 9.65 ppg to 9.75 ppg while resuming to drill ahead to wiper trip depth @;6970'.
P/U-160K S/O-86K ROT-115K GPM-276 SPP-2200 psi RPM-60 TQ-10.2K WOB-5/7K DIFF-230 psi MW-9.75 ppg ECD-11.16 ppg Max gas-395 units.;Pumped
20 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back on time w/ a 10% increase in cuttings. Obtained new SPR's. Currently flow checking well for 10 min.
Distance to well plan 6.29' 2.08' Low 5.93' Left.
5/10/2023 With string parked at 6945', monitored well for flow at rotary table and flow line. Initial flow rate at 1.8 bph that reduced to 0 bph over 30 minutes.;Pulled up hole
slow on elevators from 6945' to 5938, 177K up wt coming off bottom, parked at 5983. Worked through 20K over pulls at 6312', 6192', 6085' and 6027'. Calc hole
fill = 7.82 bbls, actual hole fill = 6.6 bbls.;Serviced rig and topdrive. Checked pump pulsation dampeners, checked pancake gap on deadman (for weight
indicator), adjusted kelly hose at topdrive and ran topdrive through derrick to verify, tightened turnbuckles on torque tube, pressure tested kelly hose connection
to 2200 psi,;changed out shaker deck jack on shaker #2 right hand side. Well on trip tank and seeing .25 bph loss rate.;TIH from 5983' to 6910' with no issue,
down wt 90K. MU topdrive on last stand, filled pipe, washed and reamed to bottom at 6970'. Calculated displacement = 17.08 bbls, actual displacement = 15.96
bbls. Circulated on bottom a couple minutes then made hook.;Cont drilling 6 3/4" hole from 6970' to 7110'. Rot wob 3 to 4K, 270 gpm-2080 psi, 60 rpm-10,100
ft/lbs on bott torque, 114 ft/hr ROP. Sliding wob 3 to 4K, 276 gpm-2100 psi. 300 psi diff, 80 ft/hr ROP. MW 9.7+/vis 53, ECD's at 11 ppg, BGG 22 units, max gas
125 units.;As we started drilling ahead we had 358 units gas just prior to bottoms up, then at bottoms up had another 174 units along with a 50% increase in
cuttings.;Cont drilling from 7110' to 7463' (sweep depth). Rot wob 4 to 5K, 276 gpm-2096 psi, 60 rpm-10,000 to 11,500 ft/lbs on bott torque, 20 to 120 ft/hr ROP.
Sliding wob 3 to 4K, 277 gpm-2131 psi, 257 psi diff, 75 ft/hr ROP, MW 9.7+/vis 52, ECD's at 11 ppg, BGG 18 units, max gas 485 units.;Pumped a 20 bbl hi-vis
nut plug condet sweep and circulated around at 274 gpm-1939 psi, 60 rpm-9100 to 11,000 ft/lbs off bottom torque and reciprocating string. Sweep came back
8.6 bbls early w/ a 15% increase in cuttings. Obtained new SPR's @ 6760'. Flow checked well = .14 bph.;Cont. drilling 6-3/4" hole F/7463'-T/7777'. P/U-175K
S/O-95K ROT-126K GPM-276 SPP-2210 psi RPM-60 TQ-11.1K WOB-5/7K DIFF-230 psi MW-9.75 ppg ECD-10.97 ppg Max gas-439 units.;Cont. drilling 6-3/4"
hole F/7777'-T/7961'. P/U-175K S/O-95K ROT-130K GPM-276 SPP-2215 psi RPM-60 TQ-11.1K WOB-5/7K DIFF-240 psi MW-9.75 ppg ECD-10.91 ppg Max
gas-377 units. Distance to well plan 2.81' 2.03' High 1.95' Left.;Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. GPM-276 SPP- 1991 psi RPM-80 TQ-11.7K
MW-9.75 ppg ECD-10.89 ppg. Sweep came back 11 bbls early w/ a 20% increase in cuttings. Obtained new SPR's. Flow checked well for 30 min, initial flow .65
bph. 25 min later static.
5/11/2023 Pulled up hole on elevators from 7961' to 6997', up wt 190K. No issues. Calculated hole fill = 7.82 bbls, actual hole fill = 7.02 bbls. Parked string at 6997' and
monitoring well on trip tank.;Serviced rig and topdrive, cleaned pump screens. Hole taking fluid at .44 bph.;TIH on elevators from 6997' to 7898', down wt 100K,
no issues. MU topdrive, filled pipe, started a 20 bbl hi-s sweep down drill string, washed and reamed to bottom at 7961'. Calculated displacement for trip = 20.74
bbls, actual displacement = 18.4 bbls.;Pumped sweep around while rot and recip at 273 gpm-1990 psi, 80 rpm-12,400 ft/lbs off bott torque. Sweep came back
6.6 bbls early and saw a 20% increase in cuttings. Max gas at bottoms up = 123 units. Saw 65 units early from B110 formation.;Cont drilling 6 3/4" hole from
7961' to 8085', Rot wob 6K, 277 gpm-2056 psi, 60 rpm-11,425 ft/lbs on bott torque,19 to 115 ft/hr ROP. Sliding wob 3 to 4K, 277 gpm-2203 psi, 275 psi diff, 70
ft/hr ROP. MW 9.7/vis 51 ECD's at 10.9 ppg, BGG 21 units, max gas 269 units.;Cont drilling from 8085' to 8392'. Rot wob 5 to 6K, 277 gpm-2186 psi, 11,700 to
12,100 ft/lbs on bott torque, 100 ft/hr ROP. MW 9.7+/vis 52, ECD's at 10.9 ppg, BGG 28 units, max gas 552 units. Received Baker liner hanger equipment
and 533 sacks lead cement in silo.;Cont. drilling 6-3/4" hole F/8392' to 8613', lost all returns, P/U off bottom, slowed pump to idle, unable to stand up well.
Dinamic loss rate = 159 bph. Shut down MP. lined up hole fill and filled back. loss rate = 86 bph. Racked back 3 stds. Spotted a 20 bbl LCM pill @ 40 ppb.;w/
Baracarb 5, 50, and walnut. P/U-192K S/O-103K ROT-137K GPM-277 SPP-2312 psi RPM-60 TQ-12.5K WOB-7K DIFF-330 psi MW-9.75 ppg ECD-10.87 ppg
Max gas-675 units.;Crew change, held PTSM. Cont. spotting LCM outside of bit. Racked back 3 more stands. P/U-210K S/O-95K. Lined up TT on the hole.
Initial static lost rate = 40 bph.;Building 300 bbls of new mud and 40 bbls worth of LCM pills at 45 ppb while monitoring well. Moving pipe every 5 min.;Finished
building back mud system and LCM pills. Current loss rate = 15.6 bph. Currently spotting 40 bbl LCM w/ 45 ppb of LCM material. Total losses for the day = 397
bbls. Distance to well plan: 2.09' .72' Low 1.96' Right.
5/12/2023 Pumped and spotted 40 bbls of 45 ppb LCM pill outside drill string with bit parked at 8207'. Pumped at idle, 112 gpm-489 psi, 9.8% return flow with hole fill on as
well. Pump pressure and return slow slowly increased to 580 psi/10.8% then started to drop off as we shut down. Lost 127 bbls spotting;pill in place. Without
hole fill pump on, fluid level stayed static in wellbore while pumping.;Monitoring well on trip tank, transfered fresh water into pits 9 and 10 and start building 300
bbls new mud for surface volume. Initial loss rate 8 bph, that fluctuated as high as 14 bph. Moved pipe every 5 to 15 minutes with no issues. Built 20 bbls of 60
ppb LCM pill in pill pit. 35.88 bbl loss.;Cont building mud, cont monitoring well on trip tank. Rolled mud pump with very little return flow, cont moving pipe with no
issue, transfered new mud into active pits. From noon to 16:00 loss rate reduced from 7.7 bph to 4.6 bph. Total 64 bbls lost since spotting pill (9 hrs).;Put well on
active system, idled pump at 112 gpm-627 psi, 3.9% return flow, pumped 6.6 bbls and lost returns, cont to pump a total 15 bbls, 631 psi, 1% flow returns. Lined
up and pumped 20 bbls of 60 ppb LCM pill and chased with 9.7+ ppg mud and spotted pill outside bit. Pump pressure varied;from 591 psi as high as 688 psi,
return flow varied from 1.2% as high as 6.9%. Lost a total of 83 bbls spotting pill in place.;Pulled up hole on elevators from 8206' to 7899' with no issue, up wt
188K. Pulled and racked back 5 stands, hole fill = 2.2 bbls. MU topdrive and pulled another 30' and parked bit at 7868'.;Monitored well on trip tank, initial return
flow at 8.8%, increased to 10.3% over 2 hours while rig mechanic and Toolpushers changed out draw works clutch pads (inner clutch pad was broke into 3
pieces). Started building an additional 125 bbls new mud in pit #10.;Broke circ with mud pump at idle, initial rate of 112 gpm-728 psi/13.4 % flow returns, varied
from 695 psi/8.5% returns to 726 psi/14.7% returns. MW- 9.5 ppg ECD- 9.61 ppg Max gas - 55 units. Lost 42.5 bbls during circ. of BU. Flow checked well for 10
min, static loss rate = 0 bph.;POOH on elevators F/7837'-T/5665' w/ no issues. P/U-188K S/O-108K.;Crew change, held PTSM. Cont. POOH. Had to wash/ream
through 2 tight spot F/4924'-T/4871' and F/4808'-T/4748'. Both cleaned right up. GPM-112 SPP-794 psi RPM-42 TQ-6.5K. Worked through multiple tight spots
on elevators w/ 20-30K over pulls F/4658'-T/2898'. P/U-80K S/O-63K.;Once inside 7-5/8" casing shoe. Flow checked well for 10 min, static loss rate = 1.2 bph.
Performed weekly function test of BOP components. Cont. POOH on elevators F/2884' to current depth of 736'.
5/13/2023 Cont POOH from 736' racking back HWDP and jars, L/D NM flex DC's, held PJSM and removed sources, plugged in and read MWD tool data. Cont POOH L/D
smart tools, motor and bit. Bit graded 1-1 and in gauge. Calculated hole fill = 62.9 bbls, actual hole fill = 75 bbls for the trip.;Serviced rig and topdrive, cleaned
pump screens, checked pulsation dampeners, functioned blind rams, cleaned rig floor and cleared catwalk. Notified AOGCC of upcoming open hole cement
plug. Monitored well on trip tank, .20 bbl loss over 1 hour.;MU 6 3/4" Smith tri-cone with no jets, bit sub with plunger style float, 5.750" OD IBS, XO, HWDP and
jars to 564'. Received tubing hanger and Wellhead Rep installed on landing joint.;Cont TIH slow from 564', filled pipe at 1456' and 2715'. Received tubing
hanger and XO pup. Wellhead Rep installed hanger on landing joint.;Hung blocks, RU and slipped/cut 110' drill line, RD and released blocks, calibrated hook
load, no losses on trip tank. Notified AOGCC of upcoming liner run and cementing of same.;Cont TIH slow, down wt 58K, to 4262' with no issues.;MU topdrive,
filled pipe at idle, then CBU staging pump rate up to 152 gpm-366 psi, 18.3% return flow, 32 rpm-5428 ft/lbs off bott torque. Had a max of 108 units gas at
bottoms up. Lost 2 bbls over 30 min of circulating.;Cont TIH slow from 4262' to 5006', up wt 95K, down wt 70K.;Cont. TIH slow F/5006'-T/6183' w/ no issues,
filling pipe every 15 stds. P/U-125K S/O-80K.;CBU @ 6183' staging pump up. GPM-156 SPP-549 psi RPM-80 TQ-8.9K Max gas- 923 units MW-9.7 ppg P/U-
135K S/O-90K.;Cont. RIOH F/6183'-T/8044'. filling pipe every 15 stds. Had 35K set down @ 6803' (coal), worked through on elevators. Had calculated pipe
displacement for the trip.;CBU @ 8044' staging pump up. GPM-156 SPP-534 psi RPM-80 TQ-11.6K Max gas- 1681 units MW-9.7 ppg P/U-175K S/O-108K ROT-
132K.;Crew change, held PTSM. Flow checked well for 10 min. Initial flow 3 bpm, dropped to static over 10 min. Washed & reamed F/8044'-T/8550'. GPM-155
SPP-544 psi RPM-30 TQ-10.2K Max gas- 29 units MW-9.75 ppg.;CBU @ 8550' while R/U HES cementers Staged up MP to GPM-161 SPP-570 psi RPM-80 TQ-
11.6K Max gas- 123 units MW-9.75 ppg P/U-190K S/O-110K ROT-140K. Held PJSM on spotting cement plug w/ rig crew, HES cmt hands, CCI, and
Baroid.;Shut down MP. L/D E-Kelly and racked back 1 std. of 4.5" DP T/8477'. M/U cmt head manifold. FOSV, 5' pup, pin head, hard line 90, swing, low torque,
and 50' 1502 hose.;Pumped 5 bbls of H2O to flush & fluid pack lines. PT'd cmt lines, 598 psi Low / 3018 psi High. Pumped 22 bbls of 10.5 ppg Tuned spacer @
2.5 bpm, 398-306 psi. Pumped 13.5 bbls of 15.8 ppg Type I II cmt w/ 1 pps of bridge maker LCM @ 2.5 bpm, 306-190 psi. Followed by 10 bbls of 10.5
ppg;Tuned spacer @ 2 bpm, 190-60 psi. Displaced w/ 98 bbls of 6% KCL PHPA to spot cmt plug @ 3.5 bpm, 60-427 psi. No losses during the job. CIP @ 04:16
hrs.;R/D cmt head manifold. POOH w/ first 7 stds slow- 30 fpm, F/8477'-T/8046'. POOH w/ remaining 8 stds at 50 fpm F/8046'-T/7522'. Lined up MP, broke circ.
Currently circulating Hi-Vis walnut sweep around to scrub pipe. GPM-160 SPP-509 RPM-80 TQ-11.6K Flow-20%.
5/14/2023 MU topdrive, broke circ staging up to 166 gpm-530 psi, 80 rpm-12,129 ft/lbs off bott torque, lined up and pumped 20 bbl low-vis nut plug sweep around to scrub
DP clean. Worked pipe from 7510' and 7535' to keep bit and stab between two coals. At bottoms up had a small amount of pea sized coal;and PH climbed from
10 to 12. Had a max of 35 units gas Once sweep hit the shakers we diverted 43 bbls of returns to cuttings box.;Did a 30 minute flow check with an initial flow
rate of .19 bph that dropped to 0 bph in 30 min. Alternated from rig pump to trip tank every 15 minutes, worked pipe while pumping at idle. No losses. Cement
sample at 10:30 was firm like peanut butter.;Washed and reamed down from 7550' to 8310', 170 gpm-642 psi, 50 rpm-9300 ft/lbs off bottom torque at 15 to 20
ft/minute. At 8310' we appeared to be into green cement seeing an increase in pump pressure to 665 psi and 1 to 4K wob.;Drilled cement from 8310' to 8550'. At
8535' cement noticeably harder. Seeing 2-5K wob, 171 gpm-665 psi, 50 rpm-10,300 ft/lbs torque. Drilled from 8535' to 8550' at 5 to 10 ft/minute.;Picked up 5'
and CBU at 171 gpm-521 psi, 20 rpm-10,900 ft/lbs off bott torque. Ran centrifuge due to 10 ppg return fluid weight. Had a max of 19 units at bottoms up.
Circulated until 9.8 ppg in/out and shut down centrifuge.;Obtained new SPR's, 10 minute flow check we had slight seepage. Pulled up hole from 8545', up wt
200K, 5 stands to 8230' with good hole fill.;Pumped a 20 bbl hi-vis nutplug sweep around at 220 gpm-726 psi, 80 rpm-10,600 ft/lbs torque. Reciprocated string.
Sweep back 5 bbls early with a 5% increase in cuttings. PH rose to 13. Shut down and had slight flow that went static over 10 minutes.;POOH F/8230'-T/563'
BHA #4 w/ no issues. L/D BHA #4. Tricone bit graded 1-1. Had calculated pipe displacement for the trip. Gave Parker casing crew and Baker tool hand 2 hr.
notice w/ 2400' to go.;Cleaned & cleared rig floor. B/D cmt head manifold. Removed BHA components from catwalk. Static loss rate = 0 bph.;R/U Parker casing
handling equip. Fill up line, Loaded catwalk racks w/ 4.5" liner tubulars. M/U FOSV to liner XO. Counted and staged centralizers on rig floor.;Crew change, held
PJSM w/ rig crew and Parker casing hand on running liner. P/U & M/U w/ BakLock 4.5" 12.6# L-80 JFE-Lion shoe track, Tested floats (ok). Cont. running 4.5"
12.6# L-80 JFE-Lion as per run tally. Filling on the fly and topping off every 10 jts. F/Surface to current depth of 2219'.
5/15/2023 Cont PU single in hole with 4 1/2" JFELion 12.6# L-80 liner, torqued to 6690 ft/lbs, from 2219' to 2887', just at surface shoe. Topped pipe with fill up hose, MU
drive sub and topdrive.;CBU at 112 gpm-120 psi staging up to 125 gpm-111 psi, max gas 4 units.;Cont PU single in open hole from 2887' to 4896' with no issue,
20 ft/min. MU drive sub and topdrive. Up wt 68K, dwn wt 50K.;CBU at 112 gpm-217 psi staging up to 126 gpm-183 psi, max gas 22 units.;Cont PU single in
open hole from 4896' to 5804' with no issue, 20 ft/min. Up wt 75K, dwn wt 52K. C/O elevators.;PU Baker 4.5" x 5.5" x 7.62" Flex Lock V liner hanger/HRD-E ZXP
liner top packer, installed LWP swivel assembly and Type 1 liner wiper plug. L/D air slips, mixed and poured xanplex, C/O elevators, MU XO and 1st stand 4 1/2"
DP, eased down to 5911' and MU topdrive.;CBU at 112 gpm-248 psi staging up to 165 gpm-341 psi. Max gas 36 units. Removed casing tongs from rig floor and
mechanic/electrician repaired power cord on iron roughneck.;Cont. RIH out of the derrick w/ 4.5" DP in open hole F/5911'-T/8511' at 15 to 20 ft/min. M/U working
std. Washed to bottom @ 8550'. Calculated pipe displacement = 46.52 bbl Act Disp.= 40.4 bbls Diff = 6.14 bbls.;CBU. Staged up MP. Initial- GPM-114 SPP-
402 Final- GPM-210 SPP-474 Max gas- 69 units. P/U-140K S/O-88K. Held PJSM w/ rig crew, HES cmt, CCI, and Baroid.;Shut down MP, racked back working
std. M/U E-Kelly & 10' pup to stump. P/U & M/U baker cmt head to 10' pup. R/U cmt hoses.;Halliburton pumped 5 bbls to flush/fill lines. Shut in at Baker cement
head and PT lines at 740 psi low 4813 psi high. Lined up Baker cement head to Halliburton, pumped 30 bbls 10.5 ppg spacer at 4 bpm 402-326 psi, followed
with 190 bbls (533 sx) 12 ppg Type I II Lead cement at 5;bpm, 326-73 psi, followed with 19 bbls (98 sx) 15.3 ppg Type I II Tail cement at 3 bpm 73-140 psi.
Baker released dart, Halliburton then displaced with 9.75 ppg 6% KCL mud at 4 bpm 49-446 psi. 35 bbls into displacement saw dart latch wiper plug. With 15
bbls to go, reduced rate;to 2 bpm-1220 psi and bumped plug/landing collar 122 bbls into displacement (calculated at 125 bbls). FCP 1418 psi. Halliburton
increased to and held 1967 psi (549 over fcp) for 1 minute. Bled back 1 bbl to truck and floats held. Slacked off on blocks, anchor holding. Increased;pressure to
2500 psi and held 5 minutes. Slacked off on blocks from 150 K to 20 K, giving us a good indication hanger was set. CIP at 03:33 on 5-16-23. Lost 5 bbls
throughout the job. Increased pressure to 3450 psi and held 1 minute to shift HRD-E and release run tool. Saw;slight bobble on weight indicator. PU weight 60K,
run tool released. RD cement hose, LD Baker cement head, MU topdrive. PU 6 to clear dogs from hanger top. Pressured up to 1366 psi on drill string and PU
slowly. Once psi started dropping, rig started;pumping and did one full circ at 294 gpm-528 psi. Had 30 bbls of spacer and 65 bbls of cement to surface. Shut
down pump, LD 10 pup jnt, MU topdrive and pumped second circulation at 438 gpm-545 psi. RD and released Halliburton crew.;L/D 10' pup and E-Kelly. POOH
racking back in the derrick F/2705' to current depth of 703'.
5/16/2023 Cont POOH with liner hanger run tool from 703'. Broke down and LD run tool.;PU diffuser, drained stack, flushed stack with black water, Broke down kelly joint
and 10' pup. Broke down cement head and XO's. RD GeoLog and Sperry shacks.;PU Baker "PBR" dress and polish mill, TIH T/ 2671' P/U 60K S/O 52K 112
GPM 105 SPP 5 RPM W/ 2668 Ft/ Lbs, 20 RPM 2668 Ft/ Lbs and 60 RPM 4000 Ft/ Lbs Tq. Tagged No-Go @2708'. Dress Liner Top and SBR as per
Baker.;Displace well F/ 9.9ppg 6% KCL EZ Mud T/ 8.4ppg CIW at 292 GPM W/ ICP at 420 psi. and FCP at 190 psi. Monitor well for flow for 30 minutes. Good
Negative Test.;POOH Laying down 44 stands of Drill Pipe F/ 2703' and L/D Dressing Mill. M/U Stack Washer and RIH with another 40 stands of Drill Pipe T/
2472', Flush through w/ CIW and L/D same. Vacuumed wiper balls through each jt, re-doped threads, and installed thread protectors on tight.;Cont. hauling of
drilling mud and cleaning tank bottoms. Submitted 24 hour notice for MIT Test to AOGCC @ 15:19.;P/U 17 jts. of HWDP off catwalk and RIH. Ran remaining 22
stds of 4.5" DP on top of HWDP. Flushed through tubulars w/ CIW and L/D same. Finished hauling off drilling mud and cleaning tank bottoms. Gave Parker
casing crew and Baker tool hand 2 hr. notice.;Cleaned & cleared rig floor. R/U testing equip. flooded & purged lines. Flushed all pits and degasser w/ BaraKleen
pill.;Pressure tested 7-5/8" x 4.5" liner lap T/3500 psi on chart for 30 min.(good test). Pumped in 2.6 bbls Bled back 2.6 bbls.;R/D testing equip. Blew down mud
lines and choke manifold. BOLD's, pulled wear ring.;Currently R/U TRS casing equip. Loading catwalk w/ 4.5" 12.6# L-80 JFE-Lion Tie back tubing.
5/17/2023 PJSM, P/U and RIH with 4-1/2" 12.6# L-80 Range II JFE-LION Tie-Back upper completion string with 5.75" Bullet Seal Assembly F/ surface T/ Chemical
Injection Mandrel @ 1190' P/U 49K S/O 40K.;R/U Pollard control lines and connect to injection mandrel and test T/ 2000 psi. Good.;Cont. RIH with upper
completion F/ 1190' T/ 2573'' banding control line to tubing. P/U 45K S/O 40K.;M/U 4-1/2" TRSV, Connect control line, function test and hold 5000 psi. on valve
for ten minutes and confirm no leakage.;Cont. RIH with upper completion F/ 2573' and locate PBR with seal assembly and No-Go @ 2719' banding control lines
to tubing. P/U 45K S/O 40K.;Terminate control lines and run them through the tubing hanger. Install check valve on TRSV line and pressure up to 5000 psi.
Wrap control lines around top of hanger and secure.;Land Tubing hanger with IA valve open and RILDS. Land Tie-Back string 1-1/2' off of No-Go at 2717.35'.
P/U 50K S/O 40K Block Wt 17K Total SS Bands: 106. B/O & L/D landing joint, Close Blind Rams & R/U equipment to perform MIT's.;Perform MIT w/ AOGCC
rep witness Bob Noble. Tested MIT-T T/3585 psi for 30 min on chart (good test). Pumped in 1.6 bbls Bled back 1.6 bbls. Tested MIT-IA T/3600 psi for 30 min
on chart (good test). Pumped in 1.1 bbls Bled back 1.1 bbls. R/D testing equip. WHR installed TWC.;Flushed both MP's, all low/high pressure mud lines, choke
manifold, MGS, and etc.. w/ Barakleen pill. Repeated same flush process w/ fresh water. R/D chains and binders on BOP stack. Loaded up remainder of JFE-
Lion tubulars. Started breaking down mud dock and pressure wash off the mats.;4 bolted well head flange and choke & kill line. Removed mouse hole, R/D IR
and tongs. Sent sub, XO's, and rack off the rig floor. R/D bails off TD, cont. w/ cleaning in the pits.;Crew change, held PTSM. Repeated same flush process for a
thrid time w/ corrosion inhibited water (Baracor 100). Blew down all lines and vacuumed out MGS. Vacuumed out degasser and pickled inside of vessel.
Removed choke and kill lines. R/D flow line, bell nipple, and flow box.;Removed ring cap from annular, inspected element (in good condition), reinstalled
element and ring cap. Removed kill & choke HCR valves from stack. Vacuumed hot tank water out of boiler #2. Cont. w/ cleaning pits. Currently opening ram
doors, removing rams, and inspecting ram cavities.
5/18/2023 Remove Rams and inspect BOP. All was in good condition. Remove Wash Pipe/ Check end play and back lash on Top Drive. All checks were within tolerance.
N/D and remove BOPE stack from well with cellar bridge cranes. N/U Dry hole tree and test Hanger Void, Neck seals and Tree T/ 500psi;Low and 5000 psi High
F/ 15 minutes. Clean shakers 1, 2 and 3. Change out Filter and check valve cartridge on Iron Roughneck. Remove Saver Sub and IBOP from Top Drive. Rebuild
5" valve on rig floor. Continue to clean pits. Change oil and filters in right angle and chain box.;Rig down mud pumps, Pull out liners and pony rods, Pressure
wash mast, Pressure wash sub, Pressure wash mud tanks, windwalls and roofs. Finish changing oil on draworks, seperate subs and organize in baskets.
Change out 4" Valve on standpipe, Change out #2 Winch Line.;Removed cover and pressure washed rotary table. Completed 180 day PM's on agitators.
Removed fitting off BOP stack and HCR valve and installed plugs. Cleaned & organized around location. CCI loaded out misc. equip./tools. Changed oil in the
rotary table, molly misted rotary, and installed cover.;Greased and worked all choke manifold valves. Pressure washed mud dock area. R/U Hilcorp's new stand
alone gas detection system.;Crew change, held PTSM. Cont. w/ power washing around the rig. Quadco rep arrived on location @ 00:00 hrs and R/D Quadco's
gas detection system. R/D iron roughneck HPU. Installed shipping beams on mezz deck. R/D over head high pressure lines and suction lines on MP's.
Inventoried MP parts.;Removed Kelley hose from TD. R/D TD torque bushing. Cont. to clean throughout rig.- roof tops, rig floor, TD, cutting tank, and hopper
house 1-3.
5/19/2023 Clean and organize Choke House, Top Drive Connex, Roughneck and Lube Room, Rig Down Top Drive HPU. Shut Down Boiler and Blow Down all heaters and
lines. Perform 180 day PM on Draworks and Brake Bands. Continue cleaning outside of Pits. Continue prepping Pump House for stack.;R/D & clean tarps,
Change out the 2" valve on MP #1 Bleeder valve, R/D Gas Buster & Choke Lines to the shakers, Pressure wash throughout rig, Clean the cellar & have CCI
vacuum it out. B/D steam lines out w/ air & begin rigging all lines down, Complete filter inventory. Prepare Gen 3 for stack out.;R/D equalizer lines between pit
modules. Laid over MGS and removed vent line. Removed 2" OTECO valve on MP #2. Perform derrick inspection, scoped derrick to half mast. L/D lower
section on torque tube. Hung off blocks, unspooled drill line, cut 12 wrap of drill line off = 57'.;Removed turnbuckles of top section of torque tube. Hung drill line,
Kelley hose, and service loop off tugger line in the derrick and secured to mast. Removed brake linkage. Folded up tarps and stowed away in mud box. Lowered
degasser into pit #4. R/D centrifuge and prepped to be craned off stand.;Serviced MP pop off's for cold stack. CCI loaded out GeoLog, and MWD/DD shack to
be barged to Beluga. Cont. w/ housekeeping/power washing around the rig.;Crew change, held PTSM. Cont. R/D and pressure washing rig. Removed wraps
from dead man. Wrapped all electric motors w/ shrink wrap. labeled & unplugging Pason cords. Rebuilt 2" OTECO valves from MP's. Removed cuttings shoots
from shakers. R/D catwalk. Disconnected air manifold system;from doghouse. Finished securing electrical & HYD lines in mast.
5/20/2023 PJSM, Remove windwalls from pits with crane. Spool up Gen 3. Remove Clamshell from Iron Roughneck, Remove Centrifuge, Feed Pump and control panel,
Load on trailer for transport to Tuboscope. Move gas buster and clean with pressure washer. Remove all hydraulic fittings from BOPE and;install plugs. Load
BOPE stack in Cradle with crane and secure same. Complete rigging down of Choke House. Clean out Boilers #1 & #2. Lay Down Catwalk V-Door slide and
disconnect all lines and prep for move. Finish prepping derrick to lay over. Pull Pason receivers from rig and place in TP shack.;PJSM, Lay over derrick onto
Draworks skid. Remove Iron Roughneck from floor, Install on carrier and take to presssure wash area and wash. Continue cleaning all catch cans, Finish
cleaning BOP stack and carrier. R/D air and water lines. Continue pressure washing out sides of mud tanks.;Fix hydraulic leak on the accumulator. Remove all
ropes & lower handrails from derrick board. Re-Install all inspection plate covers on both boilers with new gaskets.;Unpinned HYD cylinders from mast. Replaced
belts on pressure washer. Finished R/D and cleaning boiler. Folded up walkways on shaker pit module. Lowered pit roofs on all 3 pit modules. Replaced HYD
line on pit #2 module - Raising cylinder. Cont. w/ pressure washing of rig modules.;CCI loaded out rig mats, pipe racks, and misc. equip. Vacuumed out
containment around the rig. R/D electrical lines to mud tanks.;Crew change, held PTSM. Cont. pressure washing rig. Cleaned crew van and pusher truck.
Organized & inventoried TD conex. Changed HPU and catwalk HYD filters. Cleaned change shack and camp gen trailer. Cont. loading out misc. equip. & tools.
5/21/2023 Continue cleaning and organizing all modules for cold stack. Complete securing loose miscellaneous items in all modules for move tomorrow when road
restrictions are lifted. Unplug and secure all electrical lines not being used. Held discussion about the importance of driving and ensuring everybody;understands
the hazards. Transport last load from rig to Homer Barge.;Retrieve Hilcorp vehicles and prep them to take to Homer barge. Replace air line on Draworks clutch.
Clean and pressure wash top of mud pumps. Wrap SRLs in derrick and confirm all lines are tied up.;R/D remainder of electrical on MP grasshopper and stowed
away for rig move. R/D and winterized pressure washers. Blew down remainder of water system, winterized water pumps. R/D air lines and drained air tanks.
Vacuumed out and cleaned rig water tank.;Crew change, held PTSM. Drove and dropped off 2 rig pickup trucks and crew van to Homer barge landing to make
early morning barge departure to Beluga. Disconnected electrical to doghouse, retracted and lowered doghouse into rig water tank. Removed all lights from
buildings, lowered;handrails, and folded up walkways. Fueled all equip on location.
5/22/2023 Remove Choke House from rig floor with Crane. Lower wind wall on rig floor & lower windwalls on derrick board w/ crane. Load out Boiler, Generator module,
Pump #2, Top Drive HPU, Walkway Jig, Doghouse/ Water Tank, Pit modules 3 and 2, Transport to CCI yard. Remove matts. Cut and remove liner &
felt.;Continue loading rig matts and take to CCI yard, Transport Pump #1, Pit #1 and Mud Gas Separator, Transport to CCI yard. Remove Derrick from carrier
and set on trailer and secure to trailer. Crane Drilling Line spool from carrier and place on tung of trailer with Derrick. Crane and load Draworks;Skid on trailer.
Remove subbase with cranes and set on trailer. Load pony walls and matt boards on trailer and take everything to CCI yard.;Finished P/U and disposing of liner
and felt on Pearl pad. Loaded out remainder of misc. items onto floats. Rig crew laid felt, liner, and set rig mats at CCI's yard. Spotted and set pony subs on rig
mats, set roughneck HPU inside of subs. Shuffled 2 vac trucks to CCI's yard for normal maintenance;before barging them across to Beluga.;Crew change, held
PTSM. R/D crew change shack, blew down water line, and winterized w/ RV antifreeze. Rig crew traveled to CCI's yard at 05:00 hrs. to spot & set rig on mats at
07:00 hrs.
5/23/2023 Travel to CCI yard in Nikiski and re-arrange pony walls. Set Sub with cranes. Set Draworks skid on sub with cranes. Lift Choke House to floor with crane.
Assemble back yard and plug in all modules to generator terminal. Leave derrick on trailer and park on matts. Raise doghouse and pit roofs.;Continue placing rig
equipment and accessary materials on matting boards around rig. Organize inside of buildings from rig move. Assist with G & I Project at CCI Yard. Release Rig
@ 23:59 hours from Pearl 11
Activity Date Ops Summary
6/6/2023 Fox CT travel to Susan Dionne.,PJSM and permit. SIMOPS w/ AK E-Line on Pearl 10.,Travel to Pearl pad.,Nipple down BOPE stack off Pearl 10 and swing to
Pearl 11. Re-spot equipment from Pearl 10 to Pearl 11.,Rig up Fox CT on Pearl 11. M/U BHA consisting of 2.875" Down Jet Nozzle, 4-1/2' Long Flow Mandrel,
Dual Flapper, YJ CT Slip Connector.,Fill Coil, Lubricator and BOPE w/ 26 BBL's fresh water.,PT surface equipment 250 / 3000 PSI. Test good. BOPE test waived
by AOGCC by sundry.,RIH w/ BHA to circulate drilling mud out of hole.,On bottom tag fill 8498'. Pick up to 8493'. Pumped 80 BBL's down CT at 1.75 BPM to
circulate out drilling mud. Returns were immediate of tan colored drilling mud.,Start slowly POOH while still circulating fresh water down CT taking returns to Rain
for Rent tank.,OOH w/ CT. Clean water to surface. 208 BBL's total pumped. R/D injector and lubricator off well,
install night cap and secure well. Secure equipment. SDFN,Return to base.
Plan forward: Halliburton memory tool on Fox CT for CBL. Blow tubing dry w/ N2 in prep for perforating.
6/7/2023 Travel to Susan Dionne.,PJSM and permit.,Travel to location. Stand up injector and M/U 3 sections lubricator. M/U Halliburton memory tool for CBL. Stab on to
well / BOPE.,RIH w/ Halliburton memory gauge for CBL at 100' FPM.,On bottom at 09:45. Tool engaged at 09:40 POOH at 40' FPM at 09:55.,5 minute stop at
2300' then continue POOH. OOH. Down load CBL memory tool. Data good.,M/U BHA consisting of 2-1/8" Reverse Nozzle, 4-1/2' Flow Mandrel, YJ Slip CT
Connector.,RIH w/ BHA.,Still running in hole. Kick on N2 at 4500' at 1700 PSI / 1000 scf's down back side taking returns up CT to Rain for Rent tank.,Still running
in hole. Increase N2 rate to 1200 scf at 1800 PSI.,On bottom at 8498'. N2 at 2100 PSI at 1500 scf rate. 45 BBL's water returned so far.,N2 to surface. Tubing is
dry. Total of 131 BBL's water recovered. POOH.,OOH. R/D Fox CT and N2.,Return to base w/ equipment.
Plan forward: AK E-Line out in morning to perforate.
6/8/2023 Travel to Susan Dionne from AK E-Line shop.,PJSM and permit.,Travel to Pearl pad.,Spot equipment and R/U AK E-Line on Pearl 11.,PT surface equipment to
500 / 3000 PSI. Test good.,RIH w/ 20' x 2-3/4" carrier gun to shoot T-142 zone at 8392' to 8412'. N2 was to have left 1600 PSI trapped on well last night but noted
tubing PSI at 995.,SI neighboring Pearl 10. Ran jumper hose to Pearl 10. Had some freezing issues but was able to stack out 1512 PSI on both wells. Made
correlation pass across T142 zone. Sent to town for approval. Town approved.,Fire Gun ONE 20' x 2-3/4" carrier gun at T-142 zone 8392' to 8412'. CCL to TS = 9'
/ CCL depth to shot is at 8383' placing TS at 8392'. Took hard hit on tools when gun fired. Kept tool weight but lost signal. POOH. Start PSI 1512 / 5 Min 2610 / 10
Min 2775 / 15 Min 2796 / 20 Min 2808 / 25 Min 2811 / 30 Min 2812,At or near surface but kinked wire hanging in flow tubes. Could not shut tree valves initially.
Worked wire by hand and was able to get up above master valve and shut in. Bleed off. Lay down gun. All shots fired.,RDMO AK E-Line. Return equipment and
crew to base. Turn well over to production.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
NINU Pearl 11
Ninilchik
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00056 Pearl 11 Completion
Spud Date:
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# B # B
B
Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.05.15 11:23:31 -08'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.05.15 11:27:12 -08'00'
TD Shoe Depth: PBTD:
Jts.
2
68
Yes X No X Yes No 20
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated?X Yes No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Type I II 360 2.44
Type I II 173 1.16
5
21.81
Hanger/Packoff 16 Cactus 1.75 21.81 20.06
2,809.99 25.82
Pup Joint 7 5/8 29.7 L-80 CDC US Steel 4.01 25.82
1.28 2,811.27 2,809.99
Casing 7 5/8 29.7 L-80 CDC US Steel 2,784.17
Float Collar 8 5/8 BTC Innovex
Casing 7 5/8 29.7 L-80 BTC US Steel 79.29 2,890.56 2,811.27
www.wellez.net WellEz Information Management LLC ver_04818br
4
Type of Shoe:Innovex Bullnose Casing Crew:Parker
12 154
2,892.062,898.00 2,809.99
CEMENTING REPORT
Csg Wt. On Slips:
Spud Mud
6:30 5/5/2023 Surface
15.8 31.5
Bump press
Returns to surface
Bump Plug?
125.5/129
1345
62
Halliburton
FI
R
S
T
S
T
A
G
E
10.5Tuned 60
9.4 5
100
603
Csg Wt. On Hook:88,000 Type Float Collar:Innovex No. Hrs to Run:7.5
BTC Innovex 1.50 2,892.06 2,890.56
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.NINU Pearl 11 Date Run 4-May-23
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
2,809.00
Floats Held
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 2892 FC @ Top of Liner
Casing (Or Liner) Detail
Shoe 8 5/8
TD Shoe Depth: PBTD:
Jts.
1
1
183
Yes X No X Yes No 8
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? 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 5
Rotate Csg Recip Csg Ft. Min. PPG9.8
Shoe @ 8548 FC @ Top of Liner 2703.788,482.83
Floats Held
6% KCL PHPA mud
CASING RECORD
County State Alaska Supv.R Pederson / J Richardson
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.NINU Pearl 11 Date Run 14-May-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Frontier 1.47 8,553.00 8,551.53
Csg Wt. On Hook:107,141 Type Float Collar:Frontier No. Hrs to Run:25
9.8 6
98
1418
FI
R
S
T
S
T
A
G
E
10.5Tuned 30
122/125
1967
340
Hallibuton
15.3 19
Bump press
CBL
Bump Plug?
3:33 5/16/2023 2980'
8,548.008,613.00 8,482.83
CEMENTING REPORT
Csg Wt. On Slips:
6% KCL
12 190
Type of Shoe:Frontier Casing Crew:Parker
Baker Flex Lock V
www.wellez.net WellEz Information Management LLC ver_04818br
3
Every other joint up to Joint #180
Liner 4 1/2 12.6 L-80 BTC JFELion 30.64 8,551.53 8,520.89
Float Collar 5 BTC Frontier 1.33 8,520.89 8,519.56
Liner 4 1/2 12.6 L-80 BTC JFELion 30.63 8,519.56 8,488.93
Landing Collar 5 BTC JBHOBBS 1.10 8,488.93 8,487.83
Liner 4 1/2 12.6 L-80 JFE JFELion 5,742.64 8,487.83 2,745.19
Pup Joint 4 1/2 12.6 L-80 JFE JFELion 2.73 2,745.19 2,742.46
Liner Hanger 6 5/8 JFE Baker 33.68 2,742.46 2,708.78
Type I II 533 2.39
Type I II 98 1.24
5
0
Date: 06/ 13/2023
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
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: PEARL 11
PTD: 223-0j% � 2--
API: 50-133-20712-00-00
Washed and Dried Well Samples (05/12/2023)
B Set (4 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
PEARL 11
BOX 1 OF 4
2880' - 4380' MD
PEARL 11
BOX 2 OF 4
4380' - 5880' MD
PEARL 11
BOX 3 OF 4
5880' - 7410' MD
PEARL 11
BOX 4 OF 4
7410' - 8615' MD
Please include current contact information if different from above.
a a 3- 0 32.
ISLA`
RECEIVED
JUN 13 2023
A®GCC
Please acknowledge receipt by signing and returning one copy of this transmittal.
Receive Date
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 06/09/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
OPEN HOLE WIRELINE LOG (05/04/2023)
WAVEFORM SONIC (WSST) RAW & PROCESSED
Folder Contents:
Please include current contact information if different from above.
PTD: 223-032
T37720
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.06.09
16:30:36 -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
Subject:RE: [EXTERNAL] Pearl 11 Field Print, RBT, 060723
Date:Thursday, June 8, 2023 9:41:00 AM
Based on the CBL, Hilcorp has approval to proceed with perforating per Sundry 323-301.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Wednesday, June 7, 2023 8:06 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: Fwd: [EXTERNAL] Pearl 11 Field Print, RBT, 060723
Hi Bryan,
Please find attached CBL, I’m seeing cement at about 2970’. We are hoping to shoot this well
tomorrow in the T-142 near btm.
Let me know if you have any questions,
Thanks,
Jake
Sent from my iPhone
Begin forwarded message:
From: John Wendell Soules III <John.SoulesIII@halliburton.com>
Date: June 7, 2023 at 7:37:39 PM AKDT
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Barney Phillips <bphillips@hilcorp.com>, "Bryan Woolcook (Halliburton-Wp)"
<Bryan.Woolcock@halliburton.com>, Mohamed Fettah
<Mohamed.Fettah@halliburton.com>, Chris Gullett
<Christopher.Gullett@halliburton.com>
Subject: [EXTERNAL] Pearl 11 Field Print, RBT, 060723
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN
senders.
Jake,
I finally finished it. TOC is @ 2970’
John W Soules III
General Integrated Cased Hole Field Professional
Sterling District EIC
Sterling, Alaska
Email: john.soulesiii@halliburton.com
Mobile: (432) 212-2230
Office: (907) 273-3501
Anchorage: (907) 275-2600
[HALLIBURTON]
This e-mail, including any attached files, may contain confidential and privileged
information for the sole use of the intended recipient. Any review, use, distribution, or
disclosure by others is strictly prohibited. If you are not the intended recipient (or
authorized to receive information for the intended recipient), please contact the
sender by reply e-mail and delete all copies of this message.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
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is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion
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):
9,636'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
8,430psi7,835'8,555'
120'
2,897'
Perforation Depth MD (ft):
5,931'4-1/2"
16"
7-5/8"
120'
2,897'
2,980psi
6,880psi
120'
2,591'
Length Size
Proposed Pools:
TVD Burst
PRESENT WELL CONDITION SUMMARY
8,900'9,556'8,821'~2617psi N/A
MD
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Private, ADL 384372
223-032
50-133-20712-00-00
Ninilchik Beluga-Tyonek Gas Same
CO 701G
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Ninilchik Unit Pearl Prospect, Pearl 11
Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size:
12.6# / L--80 2,717'
June 6, 2023
Swell Pkr; HES TRSV 2,708' MD/2,434' TVD;144' MD/TVD
See Schematic See Schematic Tieback 4-1/2"
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
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 3:24 pm, May 23, 2023
323-301
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.05.23 14:40:48 -
08'00'
Noel Nocas
(4361)
BJM 6/2/23
*Spacing exception approved in CO 701H. SFD
CT BOP test not required if completed within 7 days of BOP test on Pearl 10. This well will have a tested, cemented, unperforated liner in the well
during the CT operations. Otherwise BOP test pressure = 3000 psi.
SFD
DSR-5/24/23
*
SFD 5/27/2023
Submit CBL to AOGCC and obtain approval before perforating.
Verify that MIT-IA to 3000 psi (part of PTD) passed prior to perforating.
10-407
CO 701H
GCW 06/02/23JLC 6/2/2023
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.06.02
15:36:14 -08'00'
RBDMS JSB 060623
Well Prognosis
Well Name:Pearl 11 API Number:50-133-20712-00-00
Current Status:Gas Producer Permit to Drill Number:223-032
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: 3386 psi @ 7696’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2617 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
Pearl 11 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
Tyonek 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 24hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 3000 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 3000psi, log CBL
6. RIH, reverse out wellbore with nitrogen, trap ~2000 psi on wellbore
7. RDMO coil tubing
8. RU E-line, PT lubricator to 3000 psi
9. Perforate and test the below sands from the bottom up:
FORMATION Sand MD TOP MD Base Total
Ftg TVD TOP TVD Bot
Tyonek T6 4706 4777 71 4101 4172
Tyonek T6A 4788 4802 14 4171 4185
Tyonek T7 4882 4935 53 4256 4309
Tyonek T9A 5045 5055 10 4400 4410
Tyonek T10 5111 5142 31 4460 4491
Tyonek T10A 5158 5175 17 4504 4521
Tyonek T11 5355 5373 18 4691 4709
Tyonek T12 5488 5511 23 4817 4840
Tyonek T17 5936 5981 45 5254 5299
Tyonek T19 6168 6200 32 5483 5515
Tyonek T20 6226 6235 9 5538 5547
Tyonek T37 6327 6356 29 5639 5668
Tyonek T65 7322 7366 44 6620 6664
Tyonek T67 7417 7454 37 6714 6751
CT BOP test not required if completed within 7 days of BOP test on Pearl
10. This well will have a tested, cemented, unperforated liner in the well
during the CT operations. -BJM
perforate multiple
Tyonek sands.
Obtain approval from AOGCC before perforating. -bjm
Well Prognosis
Tyonek T81 7632 7638 6 6925 6931
Tyonek T83 7695 7706 11 6987 6998
Tyonek T90 7855 7874 19 7145 7164
Tyonek T100 7975 7992 17 7263 7280
Tyonek T118 8145 8193 48 7429 7477
Tyonek T142 8391 8414 23 7673 7696
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 14.6 ppg EMW FIT at the surface casing shoe (0.759 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.759-0.1) = 2617 psi / 0.659 = 3971‘ 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
Shallowest Allowable Perf TVD == 3971‘ TVD
Updated by DMA 05-19-23
CURRENT SCHEMATIC
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,487’ / TVD = 7,767’
TD = 8,555’ / TVD = 7,835’
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 2,897’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,624 8,555’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,755’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.613” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,708’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (50% excess)
4-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
3
2
1
Updated by DMA 05-23-23
PROPOSED
Ninilchik Unit
Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
PBTD = 8,487’ / TVD = 7,767’
TD = 8,555’ / TVD = 7,835’
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 2,897’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,624 8,555’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,755’
4
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 144’ 3.613” 5.500” SSSV
2 1,524’ 3.958” 4.500” Chemical Injection Sub
3 2,708’ 4.875” 6.540” Liner hanger / LTP Assembly
4 2,717’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (50% excess)
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
T6 ±4,706' ±4,777' ±4,101' ±4,172' ±71' Proposed TBD
T6A ±4,788' ±4,802' ±4,171' ±4,185' ±14' Proposed TBD
T7 ±4,882' ±4,935' ±4,256' ±4,309' ±53' Proposed TBD
T9A ±5,045' ±5,055' ±4,400' ±4,410' ±10' Proposed TBD
T10 ±5,111' ±5,142' ±4,460' ±4,491' ±31' Proposed TBD
T10A ±5,158' ±5,175' ±4,504' ±4,521' ±17' Proposed TBD
T11 ±5,355' ±5,373' ±4,691' ±4,709' ±18' Proposed TBD
T12 ±5,488' ±5,511' ±4,817' ±4,840' ±23' Proposed TBD
T17 ±5,936' ±5,981' ±5,254' ±5,299' ±45' Proposed TBD
T19 ±6,168' ±6,200' ±5,483' ±5,515' ±32' Proposed TBD
T20 ±6,226' ±6,235' ±5,538' ±5,547' ±9' Proposed TBD
T37 ±6,327' ±6,356' ±5,639' ±5,668' ±29' Proposed TBD
T65 ±7,322' ±7,366' ±6,620' ±6,664' ±44' Proposed TBD
T67 ±7,417' ±7,454' ±6,714' ±6,751' ±37' Proposed TBD
T81 ±7,632' ±7,638' ±6,925' ±6,931' ±6' Proposed TBD
T83 ±7,695' ±7,706' ±6,987' ±6,998' ±11' Proposed TBD
T90 ±7,855' ±7,874' ±7,145' ±7,164' ±19' Proposed TBD
T100 ±7,975' ±7,992' ±7,263' ±7,280' ±17' Proposed TBD
T118 ±8,145' ±8,193' ±7,429' ±7,477' ±48' Proposed TBD
T142 ±8,391' ±8,414' ±7,673' ±7,696' ±23' Proposed TBD
T6
thru
T142
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.
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: 06/02/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: PEARL 11
PTD: 223-032
API: 50-133-20712-00-00
MUDLOGS - EOW DRILLING REPORTS (05/01/2023 to 05/11/2023)
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: 223-032
T37712
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.06.05
08:52:27 -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: 5/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: Pearl 11
PTD: 223-032
API: 50-133-20712-00-00
FINAL LWD FORMATION EVALUATION LOGS (05/01/2023 to 05/11/2023)
ADR, SLIM EWR- PHASE 4, DGR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-032
T37674
Kayla Junke
Digitally signed by
Kayla Junke
Date: 2023.05.26
08:56:40 -08'00'
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Dr., Suite 1400
Anchorage, AK, 99503
Re: Ninilchik, Pearl Prospect (Beluga/Tyonek Gas), Pearl 11
Hilcorp Alaska, LLC
Permit to Drill Number: 223-032
Surface Location: 324’ FNL, 714’ FEL, Sec 23, T1S, R14W, SM, AK
Bottomhole Location: 2434’ FNL, 957’ FEL, Sec 14, 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 April, 2023. 27
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.04.27 15:25:24
-08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, June 16, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
11
PEARL 11
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 06/16/2023
11
50-133-20712-00-00
223-032-0
N
SPT
2465
2230320 3500
0 30 30 30
0 0 0 0
OTHER P
Bob Noble
5/17/2023
Post completion MIT-IA per PTD.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PEARL 11
Inspection Date:
Tubing
OA
Packer Depth
0 3600 3600 3600IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN230518172329
BBL Pumped:1.1 BBL Returned:1.1
Friday, June 16, 2023 Page 1 of 1
1-Gas producer
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, June 16, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
11
PEARL 11
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 06/16/2023
11
50-133-20712-00-00
223-032-0
N
SPT
2465
2230320 3500
0 3585 3565 3556
0 0 0 0
OTHER P
Bob Noble
5/17/2023
Post compleation MIT-T per PTD.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PEARL 11
Inspection Date:
Tubing
OA
Packer Depth
0 10 10 10IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN230518171621
BBL Pumped:1.6 BBL Returned:1.6
Friday, June 16, 2023 Page 1 of 1
9
9
9
9 9
9 9
9 99
9
9
9
*DVSURGXFHU
Post compleation MIT-T
James B. Regg Digitally signed by James B. Regg
Date: 2023.06.16 15:04:02 -08'00'
Submit FIT/LOT data within 48 hrs of performing test.
BJM 4/27/23
BOP test to 3500 psi. Annular test to 2500 psi.
SFD 4/20/2023
223-032
DSR-4/13/23
50-133-20712-00-00
GCW 04/27/23JLC 4/27/2023
4/27/2023Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.04.27 15:26:05 -08'00'
Verified cement calcs. -bjm
-bjm
Verifed cement calcs. -bjm
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 GASNINILCHIK
223-032
PEARL 11
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PEARL 11Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230320NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes Surface Location lies within Fee-Private lease; Top Prod Int & TD lie within ADL0384372.2 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA-TYONEK GAS - governed by CO 701C4 Well located in a defined poolNo Spacing exception approved in CO 701H, issued April 18, 2023.5 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 includedNo Spacing exception approved in CO 701H, issued April 18, 2023.9 Operator only affected partyYes10 Operator has appropriate bond in forceNo Spacing exception approved in CO 701H, issued April 18, 2023.11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3026 psi. BOP rated to 5k (Test to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes None expected based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Normal pressure gradient ~8.5 ppg EMW) expected except for Tyonek T146 reservoir interval36 Data presented on potential overpressure zonesNA which is expected to be under-pressured (6.5 ppg EMW). Some lost circulation risk (see p. 38, 39). LCM37 Seismic analysis of shallow gas zonesNA will be available. Moderate risk of sloughing coals (see p. 23 & 39 for discusson & mitigation).38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate4/20/2023ApprBJMDate4/27/2023ApprSFDDate4/20/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 04/27/23JLC 4/27/2023
