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HomeMy WebLinkAbout224-147Nolan 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: 11/20/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20251120
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF
T41129
BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf
T41130
BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf
T41131
END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey
T41132
END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey
T41133
END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey
T41134
END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL
T41135
KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf
T41136
MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey
T41137
MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey
T41138
MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey
T41139
MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer
T41138
MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist
T41139
MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro
T41140
NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL
T41141
NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf
T41141
ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER
T41142
ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER
T41143
ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF
T41144
PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT
T41145
PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM
T41146
PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT
T41147
PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM
T41147
PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN
T41148
PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG
T41149
PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch
T41150
PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf
T41150
PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf
T41150
PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf
T41150
KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.11.20 13:27:19 -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:
PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151
PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151
Please include current contact information if different from above.
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.11.20 13:27:31 -09'00'
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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,950' N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
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
Other: N2
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
C061505, ADL384372
224-147
50-133-20732-00-00
Hilcorp Alaska, LLC
Proposed Pools:
9.3# / L-80
TVD Burst
1,262'
10,160psi
1,394'
Size
120'
1,422'
MD
3,821 - 5,386
2,980psi
6,890psi
120'120'
1,422'
November 4, 2025
Tieback 3-1/2"
7,948'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Ninilchik Unit Kalotsa 10CO 701C
Same
7,861'3-1/2"
~1250 psi
6,722'
See schematic
Length
DLH Pkr, LTP; N/A 1,209' MD/1,192' TVD; 1,226' MD/1,204' TVD, N/A
7,680' 5,770' 5,518'
Ninilchik Beluga/Tyonek Gas Pool
16"
7-5/8"
4,057 - 5,636
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
G C O
325-655
BJM 10/30/25
10-404
DSR-10/30/25A.Dewhurst 23OCT25
10/31/25
Well Prognosis
Well Name: Kalotsa 10 API Number: 50-133-20732-00-00
Current Status: New Drill Well Permit to Drill Number: 224-147
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: 1617 psi @ 3675 TVD Based on 0.44 psi/ft at deepest proposed
perf. Existing perforations are depleted and not at original pressure
Max. Potential Surface Pressure: 1250 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: .816 psi/ft using 15.7 ppg EMW FIT at the 7-5/8 surface casing shoe
(Average FIT across Paxton/Kalotsa/Dionne Structure)
Shallowest Allowable Perf TVD: MPSP/(.816-0.1) = 1250 psi / .716= 1745 TVD
(Will not perforate above top proposed perfs below)
Top of Applicable Gas Pool: 1474 MD/1432 TVD (Beluga-Tyonek)
Well Status: Online Gas producer 919 mscfd, 5 bwpd, 46 psi FTP
Brief Well Summary
Kalotsa 10 is a new drill well targeting the Tyonek and Beluga sands. Initial perforations were shot in February
2025 which IPd at ~800 mcfd. Additional perforations were added in May 2025 which doubled production
which has steadily declined since.
The objective of this sundry is to add additional infill perforations to the BEL 65-BEL 135 sands to increase the
rate.
Notes Regarding Wellbore Condition
Inclination
o Max inclination = 27.8° at 1,445 MD
o Max DLS: 4.5° at 826 MD
Min ID
o 2.992 3-1/2 liner/tubing
Recent Tags
o 5/21/25:
EL perforated BEL 134 BEL 60 w/ 2 & 2-3/8 guns
o 4/18/25:
SL - RIH w/ 2.84 GR to 4494 had to jar out
SL - RIH w/2.25 GR to 5691 - pooh
Procedure:
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250 psi low /2,000 psi high
3. RIH and perforate BEL 65 BEL 135 sands from bottom up:
Well Prognosis
Below are proposed targeted sands in order of testing (bottom/up), but
additional sands may be added/removed depending on results of these perfs,
between the proposed top and bottom perfs
Zone Top MD Btm MD Top TVD Btm TVD Footage
BEL 65 ±2,664' ±2,670' ±2,513' ±2,518' ±6'
BEL 70 ±2,690' ±2,696' ±2,536' ±2,542' ±6'
BEL 70 ±2,700' ±2,706' ±2,545' ±2,551' ±6'
BEL 72 ±2,727' ±2,733' ±2,570' ±2,575' ±6'
BEL 73 ±2,753' ±2,767' ±2,593' ±2,606' ±14'
BEL 74 ±2,784' ±2,790' ±2,621' ±2,627' ±6'
BEL 74 ±2,813' ±2,819' ±2,647' ±2,653' ±6'
BEL 78 ±2,856' ±2,862' ±2,687' ±2,692' ±6'
BEL 80 ±2,872' ±2,882' ±2,701' ±2,710' ±10'
BEL 82 ±2,917' ±2,923' ±2,742' ±2,748' ±6'
BEL 83 ±2,945' ±2,951' ±2,768' ±2,773' ±6'
BEL 90 ±2,994' ±3,009' ±2,812' ±2,826' ±15'
BEL 90 ±3,032' ±3,038' ±2,847' ±2,853' ±6'
BEL 90 ±3,041' ±3,047' ±2,855' ±2,861' ±6'
BEL 92 ±3,120' ±3,126' ±2,928' ±2,934' ±6'
BEL 92 ±3,152' ±3,164' ±2,958' ±2,969' ±12'
BEL 93 ±3,224' ±3,230' ±3,024' ±3,030' ±6'
BEL 94 ±3,236' ±3,242' ±3,035' ±3,041' ±6'
BEL 95 ±3,288' ±3,294' ±3,084' ±3,089' ±6'
BEL 95 ±3,299' ±3,305' ±3,094' ±3,099' ±6'
BEL 97 ±3,352' ±3,358' ±3,143' ±3,149' ±6'
BEL 98 ±3,385' ±3,391' ±3,174' ±3,180' ±6'
BEL 99A ±3,411' ±3,421' ±3,198' ±3,208' ±10'
BEL 99A ±3,435' ±3,446' ±3,221' ±3,231' ±11'
BEL 100 ±3,497' ±3,503' ±3,279' ±3,284' ±6'
BEL 100 ±3,512' ±3,518' ±3,293' ±3,298' ±6'
BEL 110 ±3,554' ±3,560' ±3,332' ±3,338' ±6'
BEL 120 ±3,668' ±3,674' ±3,441' ±3,447' ±6'
BEL 134 ±3,762' ±3,770' ±3,532' ±3,539' ±8'
BEL 135 ±3,849' ±3,855' ±3,616' ±3,622' ±6'
BEL 135 ±3,870' ±3,876' ±3,637' ±3,643' ±6'
BEL 135 ±3,909' ±3,915' ±3,675' ±3,681' ±6'
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)
Well Prognosis
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
i. Patch will most likely be used to avoid shutting off current production
g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
setting a plug above perforations
4. RDMO
a. If necessary, run cap string to aid with water production if encountered post perforating.
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Standard Well Procedure N2 Operations
Updated by DMA 06-02-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770 / TVD = 5,518
TD = 7,950 / TVD = 7,680
RKB to GL = 18
P
PERFORATION DETAIL - Continued on following page
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 GBCD 6.875 Surf 1,422
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992 1,226 7,948
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992 Surf 1,262
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209 3.000 6.680 DLH Packer
2 1,226 4.875 6.540 Liner hanger / LTP Assembly
3 1,262 4.790 6.340 Seal Stem
4 5,795 CIBP w/ 25 of cmt (set 3/4/25 cmt 3/8/25)
5 6,720 CIBP (2/27/25)
6 7,170 CIBP (2/26/25)
7 7,560 CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634 CIBP (2/24/25)
9 7,725 CIBP (2/23/25)
10 7,788 CIBP (2/20/25)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 60 2,607' 2,627' 2,461' 2,479' 20' 5/23/25 Open
BEL 72 2,735' 2,745' 2,577' 2,586' 10' 5/23/25 Open
BEL 81 2,898' 2,912' 2,725' 2,738' 14' 5/23/25 Open
BEL 83 2,955' 2,965' 2,777' 2,786' 10' 5/23/25 Open
BEL 88 2,970' 2,978' 2,791' 2,798' 8' 5/23/25 Open
BEL 90 3,013' 3,023' 2,830' 2,839' 10' 5/22/25 Open
BEL 91 3,079' 3,089' 2,890' 2,899' 10' 5/22/25 Open
BEL 92 3,096' 3,106' 2,906' 2,915' 10' 5/22/25 Open
BEL 92 3,130' 3,136' 2,937' 2,943' 6' 5/22/25 Open
BEL 92 3,168' 3,183' 2,972' 2,986' 15' 5/22/25 Open
BEL 93 3,199' 3,219' 3,001' 3,020' 20' 5/22/25 Open
BEL 95 3,269' 3,283' 3,066' 3,079' 14' 5/22/25 Open
BEL 100 3,468' 3,478' 3,252' 3,261' 10' 5/22/25 Open
BEL 110 3,577' 3,583' 3,354' 3,360' 6' 5/22/25 Open
BEL 133 3,737' 3,747' 3,507' 3,516' 10' 5/22/25 Open
BEL 134 3,777' 3,787' 3,546' 3,556' 10' 5/22/25 Open
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L 210 sx / T 173 sx. 39 bbls to surface.
3-1/2 Est. TOC @ TOL CBL run 2-11-25 (40% excess) L 743 sx / T 109 sx. 66 bbls
returned to surface.
16
7-5/8
9-7/8
hole
3-1/2
6-3/4
hole
2/3
Perforation Table on Page 2 TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
4
7
8
9
10
BEL 72 - 88
BEL 90 - 134
Updated by DMA 06-02-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL - Continued from previous page
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301 5,311 5,054 5,064 10 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
Updated by DMA 10-20-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770 / TVD = 5,518
TD = 7,950 / TVD = 7,680
RKB to GL = 18
16
7-5/8
9-7/8
hole
3-1/2
6-3/4
hole
2/3
TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
4
7
8
9
10
BEL 60 - 88
BEL 90 - 134
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 GBCD 6.875 Surf 1,422
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992 1,226 7,948
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992 Surf 1,262
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209 3.000 6.680 DLH Packer
2 1,226 4.875 6.540 Liner hanger / LTP Assembly
3 1,262 4.790 6.340 Seal Stem
4 5,795 CIBP w/ 25 of cmt (set 3/4/25 cmt 3/8/25)
5 6,720 CIBP (2/27/25)
6 7,170 CIBP (2/26/25)
7 7,560 CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634 CIBP (2/24/25)
9 7,725 CIBP (2/23/25)
10 7,788 CIBP (2/20/25)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 60 2,607' 2,627' 2,461' 2,479' 20' 5/23/2025 Open
BEL 65 ±2,664' ±2,670' ±2,513' ±2,518' ±6' TBD Proposed
BEL 70 ±2,690' ±2,696' ±2,536' ±2,542' ±6' TBD Proposed
BEL 70 ±2,700' ±2,706' ±2,545' ±2,551' ±6' TBD Proposed
BEL 72 ±2,727' ±2,733' ±2,570' ±2,575' ±6' TBD Proposed
BEL 72 2,735' 2,745' 2,577' 2,586' 10' 5/23/2025 Open
BEL 73 ±2,753' ±2,767' ±2,593' ±2,606' ±14' TBD Proposed
BEL 74 ±2,784' ±2,790' ±2,621' ±2,627' ±6' TBD Proposed
BEL 74 ±2,813' ±2,819' ±2,647' ±2,653' ±6' TBD Proposed
BEL 78 ±2,856' ±2,862' ±2,687' ±2,692' ±6' TBD Proposed
BEL 80 ±2,872' ±2,882' ±2,701' ±2,710' ±10' TBD Proposed
BEL 81 2,898' 2,912' 2,725' 2,738' 14' 5/23/2025 Open
BEL 82 ±2,917' ±2,923' ±2,742' ±2,748' ±6' TBD Proposed
BEL 83 ±2,945' ±2,951' ±2,768' ±2,773' ±6' TBD Proposed
BEL 83 2,955' 2,965' 2,777' 2,786' 10' 5/23/2025 Open
BEL 88 2,970' 2,978' 2,791' 2,798' 8' 5/23/2025 Open
BEL 90 ±2,994' ±3,009' ±2,812' ±2,826' ±15' TBD Proposed
BEL 90 3,013' 3,023' 2,830' 2,839' 10' 5/22/2025 Open
BEL 90 ±3,032' ±3,038' ±2,847' ±2,853' ±6' TBD Proposed
BEL 90 ±3,041' ±3,047' ±2,855' ±2,861' ±6' TBD Proposed
BEL 91 3,079' 3,089' 2,890' 2,899' 10' 5/22/2025 Open
BEL 92 3,096' 3,106' 2,906' 2,915' 10' 5/22/2025 Open
BEL 92 ±3,120' ±3,126' ±2,928' ±2,934' ±6' TBD Proposed
BEL 92 3,130' 3,136' 2,937' 2,943' 6' 5/22/2025 Open
BEL 92 3,168' 3,183' 2,972' 2,986' 15' 5/22/2025 Open
BEL 92 ±3,152' ±3,164' ±2,958' ±2,969' ±12' TBD Proposed
BEL 93 3,199' 3,219' 3,001' 3,020' 20' 5/22/2025 Open
BEL 93 ±3,224' ±3,230' ±3,024' ±3,030' ±6' TBD Proposed
PERFORATION DETAIL - Continued on following page
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L 210 sx / T 173 sx. 39 bbls to surface.
3-1/2 Est. TOC @ TOL CBL run 2-11-25 (40% excess) L 743 sx / T 109 sx. 66 bbls
returned to surface.
Updated by DMA 10-20-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL - Continued from previous page
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 94 ±3,236' ±3,242' ±3,035' ±3,041' ±6' TBD Proposed
BEL 95 3,269' 3,283' 3,066' 3,079' 14' 5/22/2025 Open
BEL 95 ±3,288' ±3,294' ±3,084' ±3,089' ±6' TBD Proposed
BEL 95 ±3,299' ±3,305' ±3,094' ±3,099' ±6' TBD Proposed
BEL 97 ±3,352' ±3,358' ±3,143' ±3,149' ±6' TBD Proposed
BEL 98 ±3,385' ±3,391' ±3,174' ±3,180' ±6' TBD Proposed
BEL 99A ±3,411' ±3,421' ±3,198' ±3,208' ±10' TBD Proposed
BEL 99A ±3,435' ±3,446' ±3,221' ±3,231' ±11' TBD Proposed
BEL 100 3,468' 3,478' 3,252' 3,261' 10' 5/22/2025 Open
BEL 100 ±3,497' ±3,503' ±3,279' ±3,284' ±6' TBD Proposed
BEL 100 ±3,512' ±3,518' ±3,293' ±3,298' ±6' TBD Proposed
BEL 110 ±3,554' ±3,560' ±3,332' ±3,338' ±6' TBD Proposed
BEL 110 3,577' 3,583' 3,354' 3,360' 6' 5/22/2025 Open
BEL 120 ±3,668' ±3,674' ±3,441' ±3,447' ±6' TBD Proposed
BEL 133 3,737' 3,747' 3,507' 3,516' 10' 5/22/2025 Open
BEL 134 ±3,762' ±3,770' ±3,532' ±3,539' ±8' TBD Proposed
BEL 134 3,777' 3,787' 3,546' 3,556' 10' 5/22/2025 Open
BEL 135 ±3,849' ±3,855' ±3,616' ±3,622' ±6' TBD Proposed
BEL 135 ±3,870' ±3,876' ±3,637' ±3,643' ±6' TBD Proposed
BEL 135 ±3,909' ±3,915' ±3,675' ±3,681' ±6' TBD Proposed
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301 5,311 5,054 5,064 10 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
Updated by DMA 10-20-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL - Continued from previous page
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
1
McLellan, Bryan J (OGC)
From:Scott Warner <scott.warner@hilcorp.com>
Sent:Tuesday, October 28, 2025 9:45 AM
To:McLellan, Bryan J (OGC)
Subject:RE: [EXTERNAL] RE: Kalotsa 10 (PTD 224-147) perf sundry
Attachments:RE: [EXTERNAL] RE: Kalotsa 2 AOGCC 10-403 325-278 PTD 216-155 Approved 05-13-25
Bryan,
We agreed on the 13.73 back in February before a deeper look was given to the reasoning behind why the FITs increased
as we con nued to drill newer/more complex wells. A er our Kalotsa 2 conversa on/suppor ng documenta on in
May, we have used the 15.7 ppg average frac gradient on numerous wells in this structure and I feel that should
con nue, especially since Kalotsa 10 reached a FIT test of 20.3 ppg without issue.
As the Kalotsa structure has been developed, deeper and higher-angle wells have been drilled, necessita ng higher
FITs to ensure well integrity, design appropriate casing depths, verify kick tolerance, con rm the forma on can
withstand higher mud weights, etc. The ini al Kalotsa wells did not require such stringent tests, hence a lower FIT was
performed. Over me, the structure has demonstrated its ability to withstand stronger FITs and one LOT.
Well FIT LOT TVD
Kalotsa 1 14.3 N/A 1360
Kalotsa 2 14.2 N/A 1379
Kalotsa 3 14.3 N/A 1316
Kalotsa 4 13.5 N/A 1410
Kalotsa 5 13.5 N/A 1071
Kalotsa 6 12.5 N/A 1258
Kalotsa 7 19.9 21.78 1415
Kalotsa 8 16.6 N/A 1666
Kalotsa 9 18.7 N/A 1369
Kalotsa 10 20.3 N/A 1408
Please let me know if there is any addi onal informa on you need to sa sfy this request and remain consistent across
the structure.
Thanks,
Scott Warner
Kenai Operations Engineer
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.
2
Office: (907) 564-4506
Cell: (907) 830-8863
To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet.
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, October 27, 2025 4:05 PM
To: Scott Warner <scott.warner@hilcorp.com>
Subject: [EXTERNAL] RE: Kalotsa 10 (PTD 224-147) perf sundry
Scott,
Apologies, I had a cut and paste error in my note below.
For this well, Kalotsa 10, Im inclined to use the same average of 13.73 ppg that was used previously as
the basis for shallowest perf calcs. Disregard the mention of Kalotsa 1 in my email below.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: McLellan, Bryan J (OGC)
Sent: Monday, October 27, 2025 4:02 PM
To: Scott Warner <scott.warner@hilcorp.com>
Subject: Kalotsa 10 (PTD 224-147) perf sundry
Scott,
Scott,
Please provide evidence that the existing perfs are depleted and the MPSP should be based on
anticipated pressure of new perfs. Even somewhat depleted perfs might yield a higher MPSP since the
deepest open perfs are much deeper than the deepest proposed perf.
Also note that in Feb of this year, Hilcorp provided an average Kalotsa well FIT/LOT of 13.73 ppg for
Kalotsa 10 because the exceptionally high FITs were excluded from the average. In the current sundry,
you proposed an average LOT value of 15.7 ppg. Please provide the data used and logic for using this
higher average. Im inclined to use the FIT from Kalotsa 1 as the basis for shallowest perf since theres
variation across wells and this errs on the side of caution.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
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: 6/18/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250618
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
AN 07RD2 50733200120200 195113 6/1/2025 AK E-LINE LDL
AN 24RD 50733202850100 207170 6/1/2025 AK E-LINE LDL
BRU 221-24 50283202020000 225027 5/29/2025 AK E-LINE CBL
KALOTSA 10 50133207320000 224147 5/21/2025 AK E-LINE Perf
KALOTSA 2 50133206590000 216155 5/25/2025 AK E-LINE Perf
PAXTON 11 50133207040000 221114 5/27/2025 AK E-LINE Perf
PAXTON 11 50133207040000 221114 5/26/2025 AK E-LINE Perf
PBU 06-12C 50029204560300 225022 5/17/2025 HALLIBURTON RBT-COILFLAG
PBU 15-32C 50029224620300 217104 5/27/2025 HALLIBURTON RBT
PBU D-01B 50029200540200 224155 5/18/2025 BAKER MRPM
PBU D-01B 50029200540200 224155 5/18/2025 HALLIBURTON RBT-COILFLAG
PBU H-18A 50029208800100 224011 5/14/2025 BAKER MRPM
PBU H-18A 50029208800100 224011 5/14/2025 HALLIBURTON RBT-COILFLAG
PBU L-109 50029230460000 201201 5/24/2025 HALLIBURTON IPROF
PBU L-115 50029230350000 201140 5/19/2025 HALLIBURTON IPROF
PBU L-117 50029230390000 201167 5/30/2025 HALLIBURTON IPROF
PBU N-07B 50029201370200 223122 6/7/2025 HALLIBURTON RBT
PBU S-100A 50029229620100 224083 5/26/2025 HALLIBURTON PPROF-LDL
PBU Z-34 50029234690000 212061 5/17/2025 HALLIBURTON IPROF-LDL
Please include current contact information if different from above.
T40566
T40567
T40568
T40569
T40570
T40571
T40571
T40572
T40573
T40574
T40574
T40575
T40575
T40576
T40577
T40578
T40579
T40580
T40581
KALOTSA 10 50133207320000 224147 5/21/2025 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.06.18 12:03:53 -08'00'
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
3. Address:Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,950 feet See Schematic feet
true vertical 7,680 feet N/A feet
Effective Depth measured 5,770 feet 1,209 & 1,226 feet
true vertical 5,518 feet 1,192 & 1,204 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)Tieback 3-1/2" 9.3# / L-80 1,292' MD 1,268' TVD
Packers and SSSV (type, measured and true vertical depth)DLH Pkr, LTP; N/A 1,209' MD/1,192' TVD 1,226' MD/1,204' TVD N/A; N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date:Contact Name:
Contact Email:
Authorized Title:Contact Phone:
Scott Warner, Operations Engineer
325-294
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
541
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
0
Size
120'
0 01674
0 760
61
measured
TVD
3-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
224-147
50-133-20732-00-00
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:
C061505, ADL384372
Ninilchik / Beluga-Tyonek Gas Pool
Ninilchik Unit Kalotsa 10
Plugs
Junk measured
Length
Production
Liner
6,722'
Casing
Structural
7,861'7,948'
120'Conductor
Surface
Intermediate
16"
7-5/8"
120'
1,422'
10,540psi
2,980psi
6,890psi
10,160psi
1,422'1,394'
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
SBy Grace Christianson at 4:37 pm, Jun 16, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.06.16 15:14:51 -
08'00'
Noel Nocas
(4361)
BJM 9/23/25 DSR-6/18/25
RBDMS JSB 061825
Page 1/1
Well Name: NINU Kalotsa 10
Report Printed: 6/2/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-20732-00-00 Field Name:Ninilchik (NINU)State/Province:ALASKA
Permit to Drill (PTD) #:224-147 Sundry #:325-294 Rig Name/No:
Jobs
Actual Start Date:4/29/2025 End Date:
Report Number
1
Report Start Date
5/21/2025
Report End Date
5/22/2025
Last 24hr Summary
PTW/PJSM. MIRU AK E-line. PT 250/2,500 psi. Perforate BEL 134 Sand (3,777' - 3,787') and BEL 133 Sand (3,737' - 3,747') with well flowing. Turn well over to
Prod Ops to flow test and SDFN.
Report Number
2
Report Start Date
5/22/2025
Report End Date
5/23/2025
Last 24hr Summary
PTW/PJSM. Perforating with AK E-line. Perforate BEL 110 Sand (3,577' - 3,583'), BEL 100 Sand (3,468' - 3,478'), BEL 95 Sand (3,269' - 3,283'), BEL 93 Sand
(3,199' - 3,219'), BEL 92 Sand (3,168' - 3,182'), BEL 92 Sand (3,130' - 3,136'), BEL 92 Sand (3,096' - 3,106'), BEL 91 Sand (3,079' - 3,089'), BEL 90 Sand (3,013' -
3,023') with well flowing. Turn well over to Prod Ops to flow test and SDFN.
Report Number
3
Report Start Date
5/23/2025
Report End Date
5/24/2025
Last 24hr Summary
PTW/PJSM. Perforating with AK E-line. Perforate BEL 88 Sand (2,970 - 2,978'), BEL 83 Sand (2,955 - 2,965'), BEL 81 Sand (2,898 - 2,912'), BEL 72 Sand (2,735 -
2,745'), BEL 60 Sand (2,607 - 2,627') with well flowing. Log well with GPT to 5,500' with well flowing. RDMO.
Perforate BEL 134 Sand (3,777' - 3,787') and BEL 133 Sand (3,737' - 3,747') with well flowing
Perforate BEL 88 Sand (2,970 - 2,978'), BEL 83 Sand (2,955 - 2,965'), BEL 81 Sand (2,898 - 2,912'), BEL 72 Sand (2,735 -g
2,745'), BEL 60 Sand (2,607 - 2,627') with
Perforate BEL 110 Sand (3,577' - 3,583'), BEL 100 Sand (3,468' - 3,478'), BEL 95 Sand (3,269' - 3,283'), BEL 93 Sandg ( , , ), ( , , ), ( ,,),
(3,199' - 3,219'), BEL 92 Sand (3,168' - 3,182'), BEL 92 Sand (3,130' - 3,136'), BEL 92 Sand (3,096' - 3,106'), BEL 91 Sand (3,079' - 3,089'), BEL 90 Sand (3,013' -(, , ),
3,023') with well flowing.
Updated by DMA 06-02-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770’ / TVD = 5,518’
TD = 7,950’ / TVD = 7,680’
RKB to GL = 18’
PERFORATION DETAIL - Continued on following page
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,226’ 7,948’
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 1,262’
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209’ 3.000” 6.680” DLH Packer
2 1,226’ 4.875” 6.540” Liner hanger / LTP Assembly
3 1,262’ 4.790” 6.340” Seal Stem
4 5,795’ CIBP w/ 25’ of cmt (set 3/4/25 cmt 3/8/25)
5 6,720’ CIBP (2/27/25)
6 7,170’ CIBP (2/26/25)
7 7,560’ CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634’ CIBP (2/24/25)
9 7,725’ CIBP (2/23/25)
10 7,788’ CIBP (2/20/25)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 72 2,735' 2,745' 2,577' 2,586' 10' 5/23/25 Open
BEL 81 2,898' 2,912' 2,725' 2,738' 14' 5/23/25 Open
BEL 83 2,955' 2,965' 2,777' 2,786' 10' 5/23/25 Open
BEL 88 2,970' 2,978' 2,791' 2,798' 8' 5/23/25 Open
BEL 90 3,013' 3,023' 2,830' 2,839' 10' 5/22/25 Open
BEL 91 3,079' 3,089' 2,890' 2,899' 10' 5/22/25 Open
BEL 92 3,096' 3,106' 2,906' 2,915' 10' 5/22/25 Open
BEL 92 3,130' 3,136' 2,937' 2,943' 6' 5/22/25 Open
BEL 92 3,168' 3,183' 2,972' 2,986' 15' 5/22/25 Open
BEL 93 3,199' 3,219' 3,001' 3,020' 20' 5/22/25 Open
BEL 95 3,269' 3,283' 3,066' 3,079' 14' 5/22/25 Open
BEL 100 3,468' 3,478' 3,252' 3,261' 10' 5/22/25 Open
BEL 110 3,577' 3,583' 3,354' 3,360' 6' 5/22/25 Open
BEL 133 3,737' 3,747' 3,507' 3,516' 10' 5/22/25 Open
BEL 134 3,777' 3,787' 3,546' 3,556' 10' 5/22/25 Open
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L – 210 sx / T – 173 sx. 39 bbls to surface.
3-1/2” Est. TOC @ TOL CBL run 2-11-25 (40% excess) L – 743 sx / T – 109 sx. 66 bbls
returned to surface.
16”
7-5/8”
9-7/8”
hole
3-1/2”
6-3/4”
hole
2/3
Perforation Table on Page 2
TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
4
7
8
9
10
BEL 72 - 88
BEL 90 - 134
Updated by DMA 06-02-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL - Continued from previous page
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301’ 5,311’ 5,054 5,064 10’ 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,950'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
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
Other: N2
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
C061505, ADL384372
224-147
50-133-20732-00-00
Hilcorp Alaska, LLC
Proposed Pools:
9.3# / L-80
TVD Burst
1,262'
10,160psi
1,394'
Size
120'
1,422'
MD
3,821 - 5,386
2,980psi
6,890psi
120'120'
1,422'
May 22, 2025
Tieback 3-1/2"
7,948'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Ninilchik Unit Kalotsa 10CO 701C
Same
7,861'3-1/2"
~700 psi
6,722'
See schematic
Length
DLH Pkr, LTP; N/A 1,209' MD/1,192' TVD; 1,226' MD/1,204' TVD, N/A
7,680'5,770'5,518'
Ninilchik Beluga/Tyonek Gas Pool
16"
7-5/8"
4,057 - 5,636
m
n
P
s
66
t
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 9:39 am, May 12, 2025
Noel Nocas
(4361)
Digitally signed by
Noel Nocas (4361)
Date: 2025.05.12
08:38:18 -08'00'
325-294
BJM 5/19/25
10-404
Perforate
SFD 5/14/2025
Obtain approval from AOGCC before setting plugs.
JLC 5/20/2025
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.05.21 03:09:05 -08'00'05/21/25
RBDMS JSB 052225
Well Prognosis
Well Name: Kalotsa 10 API Number: 50-133-20732-00-00
Current Status: New Drill Well Permit to Drill Number: 224-147
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: 775 psi @ 5359’ TVD Based on 0.014 psi/ft gas gradient
Max. Potential Surface Pressure:700 psi Based on recent shut in tubing pressure
Applicable Frac Gradient: .714 psi/ft using 13.73 ppg EMW FIT at the 7-5/8” surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(.714-0.1) = 700 psi / .614= 1140‘ TVD
(Will not perforate above top proposed perfs below)
Top of Applicable Gas Pool: 1474’ MD/1432’ TVD (Beluga-Tyonek)
Well Status: Online Gas producer – 694 mscfd, 1 bwpd, 41 psi FTP
Brief Well Summary
Kalotsa 10 is a new drill well targeting the Tyonek and Beluga sands. Initial perforations were shot in February
2025 which IP’d at ~800 mcfd.
The objective of this sundry is to add additional perforations to the BEL 59-BEL 135 sands to increase the rate.
Notes Regarding Wellbore Condition
x Inclination
o Max inclination = 27.8° at 1,445’ MD
o Max DLS: 4.5° at 826’ MD
x Min ID
o 2.992” – 3-1/2” liner/tubing
x Recent Tags
o 4/18/25:
RIH w/ 2.84” GR to 4494’ – had to jar out
RIH w/2.25” GR to 5691’ - pooh
Procedure:
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250 psi low /2,500 psi high
3. RIH and perforate BEL 59 – BEL 135 sands from bottom up with 2” 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
Zone Top MD Btm MD Top TVD Btm TVD Footage
BEL 59 ±2,564' ±2,574' ±2,423' ±2,432' ±10'
BEL 60 ±2,607' ±2,627' ±2,461' ±2,479' ±20'
BEL 65 ±2,664' ±2,670' ±2,513' ±2,518' ±6'
BEL 72 ±2,735' ±2,745' ±2,577' ±2,586' ±10'
0.014 psi/ft gas gradient ? SFD
BEL 59-BEL 135
Well Prognosis
BEL 73 ±2,753' ±2,767' ±2,593' ±2,606' ±14'
BEL 74 ±2,784' ±2,790' ±2,621' ±2,627' ±6'
BEL 74 ±2,813' ±2,819' ±2,647' ±2,653' ±6'
BEL 78 ±2,860' ±2,864' ±2,690' ±2,694' ±4'
BEL 80 ±2,872' ±2,882' ±2,701' ±2,710' ±10'
BEL 81 ±2,898' ±2,912' ±2,725' ±2,738' ±14'
BEL 82 ±2,917' ±2,923' ±2,742' ±2,748' ±6'
BEL 83 ±2,945' ±2,951' ±2,768' ±2,774' ±6'
BEL 83 ±2,955' ±2,965' ±2,777' ±2,786' ±10'
BEL 88 ±2,970' ±2,978' ±2,791' ±2,798' ±8'
BEL 90 ±2,994' ±3,009' ±2,812' ±2,826' ±15'
BEL 90 ±3,013' ±3,023' ±2,830' ±2,839' ±10'
BEL 90 ±3,032' ±3,038' ±2,847' ±2,843' ±6'
BEL 90 ±3,041' ±3,047' ±2,855' ±2,861' ±6'
BEL 91 ±3,079' ±3,089' ±2,890' ±2,899' ±10'
BEL 92 ±3,096' ±3,106' ±2,906' ±2,915' ±10'
BEL 92 ±3,120' ±3,126' ±2,928' ±2,934' ±6'
BEL 92 ±3,130' ±3,136' ±2,937' ±2,943' ±6'
BEL 92 ±3,158' ±3,164' ±2,963' ±2,969' ±6'
BEL 92 ±3,168' ±3,183' ±2,972' ±2,986' ±15'
BEL 93 ±3,199' ±3,219' ±3,001' ±3,020' ±20'
BEL 93 ±3,224' ±3,230' ±3,024' ±3,030' ±6'
BEL 94 ±3,236' ±3,242' ±3,035' ±3,041' ±6'
BEL 95 ±3,269' ±3,283' ±3,066' ±3,079' ±14'
BEL 97 ±3,352' ±3,358' ±3,143' ±3,149' ±6'
BEL 98 ±3,385' ±3,391' ±3,174' ±3,180' ±6'
BEL 99 ±3,411' ±3,421' ±3,198' ±3,207' ±10'
BEL 100 ±3,468' ±3,478' ±3,252' ±3,261' ±10'
BEL 100 ±3,497' ±3,503' ±3,279' ±3,285' ±6'
BEL 100 ±3,512' ±3,518' ±3,293' ±3,299' ±6'
BEL 110 ±3,554' ±3,560' ±3,332' ±3,338' ±6'
BEL 110 ±3,577' ±3,583' ±3,354' ±3,360' ±6'
BEL 133 ±3,737' ±3,747' ±3,507' ±3,516' ±10'
BEL 134 ±3,762' ±3,770' ±3,532' ±3,539' ±8'
BEL 134 ±3,777' ±3,787' ±3,546' ±3,556' ±10'
BEL 135 ±3,844' ±3,854' ±3,611' ±3,621' ±10'
BEL 135 ±3,908' ±3,918' ±3,674' ±3,684' ±10'
BEL 135 ±3,944' ±3,950' ±3,710' ±3,716' ±6'
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
Well Prognosis
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
i. Patch will most likely be used to avoid shutting off current production
g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to
setting a plug above perforations
4. RDMO
a. If necessary, run cap string to aid with water production if encountered post perforating.
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Standard Well Procedure – N2 Operations
Obtain AOGCC approval before setting plugs. -bjm
Updated by CJD 3-21-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770’ / TVD = 5,518’
TD = 7,950’ / TVD = 7,680’
RKB to GL = 18’
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L – 210 sx / T – 173 sx. 39 bbls to surface.
3-1/2” Est. TOC @ TOL CBL run 2-11-25 (40% excess) L – 743 sx / T – 109 sx. 66 bbls
returned to surface.
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,226’ 7,948’
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 1,262’
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209’ 3.000” 6.680” DLH Packer
2 1,226’ 4.875” 6.540” Liner hanger / LTP Assembly
3 1,262’ 4.790” 6.340” Seal Stem
4 5,795’ CIBP w/ 25’ of cmt (set 3/4/25 cmt 3/8/25)
5 6,720’ CIBP (2/27/25)
6 7,170’ CIBP (2/26/25)
7 7,560’ CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634’ CIBP (2/24/25)
9 7,725’ CIBP (2/23/25)
10 7,788’ CIBP (2/20/25)
6-3/4”
hole
2/3
Perforation Table on Page 2
TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
4
7
8
9
10
Updated by SRW 3-21-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301’ 5,311’ 5,054 5,064 10’ 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
Updated by SRW 05-06-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770’ / TVD = 5,518’
TD = 7,950’ / TVD = 7,680’
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,226’ 7,948’
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 1,262’
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209’ 3.000” 6.680” DLH Packer
2 1,226’ 4.875” 6.540” Liner hanger / LTP Assembly
3 1,262’ 4.790” 6.340” Seal Stem
4 5,795’ CIBP w/ 25’ of cmt (set 3/4/25 cmt 3/8/25)
5 6,720’ CIBP (2/27/25)
6 7,170’ CIBP (2/26/25)
7 7,560’ CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634’ CIBP (2/24/25)
9 7,725’ CIBP (2/23/25)
10 7,788’ CIBP (2/20/25)
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 59 ±2,564' ±2,574' ±2,423' ±2,432' ±10' TBD Proposed
BEL 60 ±2,607' ±2,627' ±2,461' ±2,479' ±20' TBD Proposed
BEL 65 ±2,664' ±2,670' ±2,513' ±2,518' ±6' TBD Proposed
BEL 72 ±2,735' ±2,745' ±2,577' ±2,586' ±10' TBD Proposed
BEL 73 ±2,753' ±2,767' ±2,593' ±2,606' ±14' TBD Proposed
BEL 74 ±2,784' ±2,790' ±2,621' ±2,627' ±6' TBD Proposed
BEL 74 ±2,813' ±2,819' ±2,647' ±2,653' ±6' TBD Proposed
BEL 78 ±2,860' ±2,864' ±2,690' ±2,694' ±4' TBD Proposed
BEL 80 ±2,872' ±2,882' ±2,701' ±2,710' ±10' TBD Proposed
BEL 81 ±2,898' ±2,912' ±2,725' ±2,738' ±14' TBD Proposed
BEL 82 ±2,917' ±2,923' ±2,742' ±2,748' ±6' TBD Proposed
BEL 83 ±2,945' ±2,951' ±2,768' ±2,774' ±6' TBD Proposed
BEL 83 ±2,955' ±2,965' ±2,777' ±2,786' ±10' TBD Proposed
BEL 88 ±2,970' ±2,978' ±2,791' ±2,798' ±8' TBD Proposed
BEL 90 ±2,994' ±3,009' ±2,812' ±2,826' ±15' TBD Proposed
BEL 90 ±3,013' ±3,023' ±2,830' ±2,839' ±10' TBD Proposed
BEL 90 ±3,032' ±3,038' ±2,847' ±2,843' ±6' TBD Proposed
BEL 90 ±3,041' ±3,047' ±2,855' ±2,861' ±6' TBD Proposed
BEL 91 ±3,079' ±3,089' ±2,890' ±2,899' ±10' TBD Proposed
BEL 92 ±3,096' ±3,106' ±2,906' ±2,915' ±10' TBD Proposed
BEL 92 ±3,120' ±3,126' ±2,928' ±2,934' ±6' TBD Proposed
BEL 92 ±3,130' ±3,136' ±2,937' ±2,943' ±6' TBD Proposed
BEL 92 ±3,158' ±3,164' ±2,963' ±2,969' ±6' TBD Proposed
BEL 92 ±3,168' ±3,183' ±2,972' ±2,986' ±15' TBD Proposed
BEL 93 ±3,199' ±3,219' ±3,001' ±3,020' ±20' TBD Proposed
BEL 93 ±3,224' ±3,230' ±3,024' ±3,030' ±6' TBD Proposed
BEL 94 ±3,236' ±3,242' ±3,035' ±3,041' ±6' TBD Proposed
BEL 95 ±3,269' ±3,283' ±3,066' ±3,079' ±14' TBD Proposed
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L – 210 sx / T – 173 sx. 39 bbls to surface.
3-1/2” Est. TOC @ TOL CBL run 2-11-25 (40% excess) L – 743 sx / T – 109 sx. 66 bbls
returned to surface.
16”
7-5/8”
9-7/8”
hole
3-1/2”
6-3/4”
hole
2/3
Perforation Table on Page 2
TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
4
7
8
9
10
Updated by SRW 05-06-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
BEL 97 ±3,352' ±3,358' ±3,143' ±3,149' ±6' TBD Proposed
BEL 98 ±3,385' ±3,391' ±3,174' ±3,180' ±6' TBD Proposed
BEL 99 ±3,411' ±3,421' ±3,198' ±3,207' ±10' TBD Proposed
BEL 100 ±3,468' ±3,478' ±3,252' ±3,261' ±10' TBD Proposed
BEL 100 ±3,497' ±3,503' ±3,279' ±3,285' ±6' TBD Proposed
BEL 100 ±3,512' ±3,518' ±3,293' ±3,299' ±6' TBD Proposed
BEL 110 ±3,554' ±3,560' ±3,332' ±3,338' ±6' TBD Proposed
BEL 110 ±3,577' ±3,583' ±3,354' ±3,360' ±6' TBD Proposed
BEL 133 ±3,737' ±3,747' ±3,507' ±3,516' ±10' TBD Proposed
BEL 134 ±3,762' ±3,770' ±3,532' ±3,539' ±8' TBD Proposed
BEL 134 ±3,777' ±3,787' ±3,546' ±3,556' ±10' TBD Proposed
BEL 135 ±3,844' ±3,854' ±3,611' ±3,621' ±10' TBD Proposed
BEL 135 ±3,908' ±3,918' ±3,674' ±3,684' ±10' TBD Proposed
BEL 135 ±3,944' ±3,950' ±3,710' ±3,716' ±6' TBD Proposed
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301’ 5,311’ 5,054 5,064 10’ 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/02/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250402
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG
BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf
BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf
CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG
IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf
KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF
KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF
KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP
MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey
MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF
MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF
MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper
MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL
MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut
PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT
PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey
PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP
PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40256
T40256
T40257
T40257
T40258
T40259
T40260
T40261
T40262
T40263
T40264
T40265
T40266
T40267
T40268
T40269
T40270
T40271
T40272
KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.02 12:55:27 -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: 126.3' 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 1,385'
3-1/2"L-80 7,678'
3-1/2"L-80 1,240'
24. Open to production or injection?Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production:Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press.24-Hour Rate
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl:Water-Bbl:
0 1520
3/14/2025 24
Flow Tubing
1
695
N/A6950
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9.2#
1,262'
1,203'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
3/5/2025
Date of Test:Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
CASING, LINER AND CEMENTING RECORD
2586' FSL, 1198' FEL, Sec 12, T1S, R14W, SM, AK
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,
AMOUNT
PULLED
208695
208210
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.
CBL 2-11-25, Perf and GPT logs, LWD (PCG, ADR, PWD, DDSR, CTN, ALD, P4M)
N/A
N/A
N/A
SETTING DEPTH TVD
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2233665
2233813
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
209863 2233349
50-133-20732-00-00January 23, 2025
N/A
NINU Kalotsa 10February 3, 20252075' FSL, 468' FWL, Sec 7, T1S, R13W, SM, AK
144.3'
Beluga/Tyonek Gas Pool
C061505, ADL 384372
7,950' MD / 7,680' TVD
5,770' MD / 5,518' TVD
2449' FSL, 710' FEL, Sec 12, T1S, R14W, SM, AK
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
2/19/2025 224-147 / 325-061
6-3/4"
TOP HOLE SIZE
PACKER SET (MD/TVD)
Conductor
Tieback AssyTieback
TUBING RECORD
L - 743 sx / T - 109 sx
Surface
1,422'
9.2#
Surface
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
1,226'7,948'
Surface 9-7/8"
Driven
Surface L - 210 sx / T - 173 sx
G
s d 1
0 p
dB P
L
s
(att
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
G
Received 3/24/2025
DSR-4/17/25BJM 11/10/25
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval T 3 4,057' 3,821'
889' 885'
966' 961'
1166' 1151'
3955' 3720'
4009' 3763'
4177' 3941'
7132' 6868'
7198' 6934'
7476' 7209'
7545' 7278'
7643' 7375'
7683' 7415'
7862' 7593'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
T 142
T 115
Beluga 136
Sterling 6
Tyonek Top
T 90
Beluga A
Beluga 1
T 5
T 87
T 118
T 120
T 135
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
INSTRUCTIONS
Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Reports, Definitive Directional Survey
Authorized Title: Drilling Manager
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS
N
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.03.24 16:23:07 -
08'00'
Sean
McLaughlin
(4311)
Updated by CJD 3-21-25
Schematic
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 5,770’ / TVD = 5,518’
TD = 7,950’ / TVD = 7,680’
RKB to GL = 18’
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% Lead excess) L – 210 sx / T – 173 sx. 39 bbls to surface.
3-1/2” Est. TOC @ TOL CBL run 2-11-25 (40% excess) L – 743 sx / T – 109 sx. 66 bbls
returned to surface.
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,226’ 7,948’
3-1/2" Prod Tieback 9.3 L-80 EUE 2.992” Surf 1,262’
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,209’ 3.000” 6.680” DLH Packer
2 1,226’ 4.875” 6.540” Liner hanger / LTP Assembly
3 1,262’ 4.790” 6.340” Seal Stem
4 5,795’ CIBP w/ 25’ of cmt (set 3/4/25 cmt 3/8/25)
5 6,720’ CIBP (2/27/25)
6 7,170’ CIBP (2/26/25)
7 7,560’ CIBP w/ 4 gallons of cmt (2/24/25)
8 7,634’ CIBP (2/24/25)
9 7,725’ CIBP (2/23/25)
10 7,788’ CIBP (2/20/25)
6-3/4”
hole
2/3
Perforation Table on Page 2
TY 140
TY 140
TY 118
TY 67 - 80
TY 65
TY 63 - 37
TY 3 - 18
1
4
5
6
7
8
9
10
Updated by SRW 3-21-25
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 4,057' 4,064' 3,821 3,828 7' 3/8/25 Open
TY_3 4,066' 4,077' 3,830 3,841 11' 3/8/25 Open
TY_5 4,178' 4,184' 3,941 3,947 6' 3/8/25 Open
TY_5 4,200' 4,207' 3,963 3,970 7' 3/8/25 Open
TY_5A 4,256' 4,262' 4,019 4,025 6' 3/8/25 Open
TY_5B 4,295' 4,301' 4,057 4,063 6' 3/8/25 Open
TY_6 4,323' 4,341' 4,085 4,103 18' 3/8/25 Open
TY_6 4,370' 4,376' 4,132 4,138 6' 3/8/25 Open
TY_7 4,459' 4,473' 4,220 4,234 14' 3/7/25 Open
TY_8 4,528' 4,542' 4,288 4,302 14' 3/7/25 Open
TY_9A 4,626' 4,646' 4,385 4,405 20' 3/7/25 Open
TY_10B 4,707' 4,713' 4,466 4,472 6' 3/7/25 Open
TY_10B 4,738' 4,743' 4,496 4,501 5' 3/7/25 Open
TY_11A 4,845' 4,850' 4,602 4,607 5' 3/7/25 Open
TY_14 5,251' 5,257' 5,005 5,011 6' 3/6/25 Open
TY_15 5,301’ 5,311’ 5,054 5,064 10’ 3/6/25 Open
TY_15 5,322' 5,327' 5,075 5,080 5' 3/6/25 Open
TY_16 5,405' 5,413' 5,157 5,165 8' 3/6/25 Open
TY_17 5,438' 5,474' 5,190 5,226 36' 3/5/25 Open
TY_17 5,477' 5,504' 5,229 5,255 27' 3/5/25 Open
TY_17 5,512' 5,518' 5,263 5,269 6' 3/5/25 Open
TY_17 5,524' 5,532' 5,275 5,283 8' 3/5/25 Open
TY_17 5,542' 5,548' 5,293 5,299 6' 3/4/25 Open
TY_18 5,565' 5,571' 5,316 5,321 6' 3/4/25 Open
TY_18 5,609' 5,636' 5,359 5,386 27' 3/4/25 Open
TY_37 5,814' 5,839' 5,562 5,587 25' 3/1/25 Isolated
TY_37 5,856' 5,864' 5,604 5,611 8' 3/1/25 Isolated
TY_43 6,026' 6,049' 5,772 5,795 23' 3/1/25 Isolated
TY_43 6,057' 6,069' 5,803 5,815 12' 3/1/25 Isolated
TY_53 6,540' 6,567' 6,281 6,308 27' 2/27/25 Isolated
TY_65 6,755' 6,785' 6,494 6,524 30' 2/27/25 Isolated
TY_67 6,824' 6,836' 6,563 6,575 12' 2/26/25 Isolated
TY_90 7,202' 7,208' 6,938 6,944 6' 2/25/25 Isolated
TY_90 7,213' 7,223' 6,948 6,958 10' 2/25/25 Isolated
TY_90 7,228' 7,246' 6,963 6,981 18' 2/25/25 Isolated
TY_90 7,273' 7,293' 7,008 7,028 20' 2/25/25 Isolated
TY_90 7,324' 7,330' 7,059 7,065 6' 2/25/25 Isolated
TY_118 7,582' 7,640' 7,315 7,372 58' 2/23/25 Isolated
TY_140 7,752' 7,783' 7,484 7,514 31' 2/20/25 Isolated
TY_140 7,796' 7,830' 7,527 7,561 34' 2/19/25 Isolated
Page 1/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Jobs
Actual Start Date:1/19/2025 End Date:2/9/2025
Report Number
1
Report Start Date
1/19/2025
Report End Date
1/20/2025
Operation
Blew down surface equipment and lines, cleaned tank bottoms, gathered gas alarm sensors, removed equalizer lines between pit mods and jumpers in pump skids, RD
centrifuge and removed overhead hooch, lowered vac degasser in pit 4, installed shipping blocks on shakers, cleaned suction manifolds on mud pumps and inspected
valves/seats etc, winterized charge pumps and liner wash pumps, cleaned and stripped iron roughneck for shipping/repair work, removed rotary table cover and cleaned
table, RD gen 3 skid, RD clam shell on rig floor.
Brought in crane and removed windwalls and clam shell, folded beaver slide over and removed BOP stack from cellar to cradle, cl eaned and un-dressed topdrive, cradled
same and L/D, removed cement silo and upright water tank, layed down MGS and removed vent pipe, removed HandyBerm, bridled up blocks, prepped derrick board for
lay down, installed shipping beams, pressure washed in cellar, removed service shacks.
Removed "T" bar, scoped mast, L/D lower section of TQ tube onto catwalk. Removed turnbuckles in mast, hung blocks. Un-spooled drill line and cut off 14 wraps. R/D
bleeder and S-pipe. Removed covers from mast HYD cylinders. Unplugged misc. Pason cables, Hung Kelley hose, service loop, and drill line off tugger in the mast. Laid
over mast, un-pinned cylinders, and pressure washed. Laid over beaver slide and R/D HYD lines. Worked on un-plugging electrical.
Shut down water through out the rig, blew down lines, and R/D same. Cont. R/D electrical. R/D TDS HPU power & HYD lines. Organized 20' parts conex. Shut in boilers,
Blew down steam lines, removed steam traps, and R/D same. R/D brake linkage & drive line. Prepped dog house to lower into water tank. Shut down, blew down, and
R/D air lines.
Report Number
2
Report Start Date
1/20/2025
Report End Date
1/21/2025
Operation
CCI on location at 06:00 with second crane and bed truck. Staged crane, picked choke house, removed back yard modules and catwalk, lowered and removed
doghouse/water tank, staged second crane and picked derrick off carrier, carrier off sub, sub off pony walls. Moved pony walls and start stacking rig mats.
Cont stacking mats and cleaning up exposed liner/felt. CCI put down sand then leveled rig footprint. Ran string line and marked out for felt/liner.
Laid felt, liner, and set rig mats. N/U Diverter speed head, spacer spool, and T.
Crew change, held PJSM. Spotted & set pony subs. Working on misc. projects & housekeeping.
Report Number
3
Report Start Date
1/21/2025
Report End Date
1/22/2025
Operation
Rig movers on location, spot cranes and set sub over well and center, set draw works and derrick on sub and pin, spot in doghouse and pit module #1, set jig and pump
skids, set remainig pit modules, set gen skid and top drive hpu, set boiler, raise doghouse, raise derrick, set annular in cellar, set choke house.
Spot in catwalk and raise ramp. raise gas buster, set windwalls on pits and set centrifuge, hook up electric and steam lines hook up water and mud lines, set water tank
and third party shacks, spot in gen 3, continue riggin up and working on rig acceptance checklist.
Un-tied drill line, Kelley hose, and service loop. hammered up S-pipe. M/U turnbuckles on upper section of TQ tube. Hooked up gas alarms. Removed shipping blocks on
shakers. R/U centriguge, equilizerlines, and hopper house jumper hoses on pit system. Spooled on drill line and slipped on additional line. R/U weight indicator, inspected
derrick. Scoped derrick while P/U lower section of TQ tube. M/U strong back to TQ tube. R/U hoisting gear. Hoisted craddle/TDS to rig floor. Pinned TDS/dog bones to
blocks.
Crew change, held PTSM. Cont. with R/U and working through rig acceptance check list. M/U Kelley hose & service loop to TDS. Slipped TQ bushing onto TQ tube,
pinned TQ bushing to TDS. Installed saver-sub, bails, and elevators on TDS. R/U tongs and installed pull back/ sub lines. Funtion tested TDS robotics and IR. Inspected
& tested valves in pit system. Brought on water to Hydro test pits.
Report Number
4
Report Start Date
1/22/2025
Report End Date
1/23/2025
Operation
N/U Diverter assembly and vent line, M/U hydraulic lines, remove shippling beam install riser and flow line.
Function test diverter system with state inspector Bob Noble, Funtion test PVT sensors and Gas alarms
Load Pipe on racks, strap and tally, build spud mud and test surface lines and stack tighten flange on knife valve.
P/U 4 jts of 4.5" DP and tagged bottom at 130', RAcked back pipe in the derrick. Installed rotary table mouse hole.
P/U singles, built 4.5" DP stds in rotary table mouse hole, and racked back in the derrick (37 stds total). M/U 4 stds of HWDP, and racked back.
Crew change, held PTSM. Finished P/U remainder of HWDP (4 stds). L/D rotary table mouse hole. TIH w/ 2 stds of HWDP. Filled conductor with spud mud to displace
out water, and checked for leaks (ok). Racked back HWDP. M/U jar std and racked back in derrick.
Cleaned & cleared rig floor. Obtained RKB's.
M/U first stage of 9-7/8" surface directional BHA #1 F/surface-T/123'. M/U 9-7/8" 6 bladed PDC bit, mud motor w/ 1.5° bend, Measured to obtain off set, P/U MWD tools,
uploaded MWD data. Performed shallow pulse test (ok). Held PJSM, loaded sources.
Report Number
5
Report Start Date
1/23/2025
Report End Date
1/24/2025
Operation
Drill 9 7/8'' Hole Section f/ 131' t/ 681' 450 gpm 1496 psi 50 rpm 4.3k tq on bottom, 3k WOB, Max gas 51 units, 41k PUW 41k SOW 43k ROT
Drill 9 7/8'' hole section f/ 681' t/ 1427' 500 gpm 1754 psi 50 rpm 5.2k tq on bottom, 7k WOB, 9 ppg, 51k PUW 50k SOW 52k SOW ECD-9.67 ppg Max gas-80 units.
Distance to well plan: 11.85' 9.47' High 7.12' Right.
Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back on time w/ a 30% increase in cuttings. Circulated till shakers cleaned up. Flow checked well (static).
POOH on elevators F/1427-T/BHA #1. Racked back HWDP,and L/D jar std. P/U-54K S/O-53K
Serviced rig- Inspected & greased crown, TDS, wash pipe, IR, DWKS, brake linkage, and drive shaft. Inspected saver-sub. Changed out trip Sala block.
Held PJSM, removed sources, plugged in and downloaded MWD data. L/D MWD tools. Milked motor & B/O bit. Bit graded 1-1 in gauge, L/D same.
Cleaned & cleared rig floor. Adjusted chain on stack to center riser. P/U and test run hanger, L/D same. Held PJSM on running casing.
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169Permit to Drill (PTD) #:224-147
Wellbore API/UWI:50-133-20732-00-00
Page 2/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
P/U & M/U 7-5/8" shoe track, tested floats (ok). Cont. running 7-5/8" 29.7# L-80 GBCD surface casing as per run tally F/85'-T/1422' w/ no issues. M/U LJ/hanger, landed
hanger on seat, P/U 1' off seat.
M/U XO, broke circ. Stagged up MP to 5 bpm. GPM-208 SPP-42 psi Flow-20% MW- 9 ppg Max gas- 16 units.
Report Number
6
Report Start Date
1/24/2025
Report End Date
1/25/2025
Operation
Continue Circ and Cond mud for cement job spot in cementers, blow down top drive, break out circ swedge.
R/U cement head and lines, R/U mud line to trucks, have PJSM, break circ with fresh water, shut in and PT lines to 400/2500 psi, pump 59 bbls 10.5 ppg spacer, 78 bbls
12.5 ppg lead cement, 38 bbls 15.3 ppg Tail Cement, Drop top plug displace cemtn w/ 61 bbls of mud @ 5 bpm 510 psi, bump plugs 900 psi hold for 5 min bleed off and
check floats good bled back 3/4 bbls, CIP 09:30 hrs, R/D cement equipment blow down lines.
M/U stack washer and flush stack with black water, flush and wash inside diverter annular.
Nipple down diverter assembly, break bolts and remove vent line, break down knife valve and riser, remove T and slip lock head, bring in B section of wellhead and N/U
as per Vault rep. Test hanger neck seals.
N/U BOP Stack and choke and kill lines. Funtion tested rams & annular. Flooded stack, mud lines,CM, and purged out air.
Tested BOP's on 4.5" & 3.5" test jt. and gas alarm system as per AOGCC regulations. AOGCC Jim Regg waived witness. Had 3 hr test time with no FP's.
R/U testing equip. Pulled test plug and installed 9" wear ring. L/D test jt. Cont. building second batch of KCL mud.
Pressure tested 7-5/8" surface casing T/3500 psi for 30 min on a chart (ok). R/D & B/D testing equip.
Serviced rig- Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive line. Inspected saver-sub (ok). Off line greased CM, inside
manuals, HCR's, and mezz valve.
M/U 6.75" 5 bladed PDC bit to mud motor w/ 1.5° bend. Obtained off set. M/U MWD tools. Currently uploading MWD data.
Report Number
7
Report Start Date
1/25/2025
Report End Date
1/26/2025
Operation
Finish upload MWD, shallow test tools and load sources, RIH w/ HWDP and jars from derrick.
RIH P/U DP 20 jts t/ 1337 and tag
Drill FE f/ 1337' t/ 1422' Drill 20' of new hole t/ 1447'
Displace well t/ 9.1 ppg 6% kcl polymer mud system
R/U test equipment and perfrom FIT t/ 20.3 ppg EMW, R/D test equipment and send results to state for aproval.
Drill Production section f/ 1447' t/ 1715' 240 gpm 1215psi 50 RPM 4.7k tq on bottom 2-5k WOB Max gas 169 units, MW 9.1 ppg ECD 9.9 ppg
Cont. directional drilling 6.75" production hole F/1707'-T/2254'. Obtained SPR's at 1931'. P/U-60K S/O-52K ROT-56K GPM-290 SPP- 1785 psi Diff- 125 psi RPM-60
TQ-4.4K WOB-5K MW-9.15 ppg ECD-10.09 ppg Max gas- 414 units. Pumped 20 bbl Hi-Vis sweep at 1931', sweep came back on time with a 100% increase in cuttings.
Crew change, held PTSM. Cont. directional drilling 6.75" production hole F/2254'-T/2492'. P/U-60K S/O-52K ROT-56K GPM-275 SPP-1641 psi Diff-97 psi RPM-60
TQ-4.7K WOB-6K MW-9.15 ppg ECD-10.15ppg Max gas- 392 units. Distance to well plan: 5.39' 5.39' High 1.08' Right.
CBU, obtained SPR's, and flow checked (static).
POOH on elevators F/2492'-T/1302'. P/U-69K S/O-57K
Servied rig- Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive line. cleaned suction screens of MP's. Inspected saver-sub.
P/U & singled in the hole w/ DP F/1302' to current depth of 1741'.
Report Number
8
Report Start Date
1/26/2025
Report End Date
1/27/2025
Operation
RIH f/ 1741' t/ 2492' 38 jts total
Drill 6 3/4 hole section f/ 2492' t/ 2840' 275 gpm 1670' 60 rpm 4.7k tq on bottom, Max gas 180 units MW 9.15 ppg ECD 10.41 ppg, 71k PUW 57k SOW 65k ROT
Drill 6 3/4'' Hole f/ 2840' t/ 3497' 273 gpm 1815 psi 60 rpm 5.8k tq on bottom, WOB 8k, MW 9.25 ppg ECD 10.8 ppg Max gas-814 units.
CBU, obtained SPR's, and flow checked well (slight seepage). GPM-276 SPP-1687 psi Flow-21% RPM-60 TQ-5K MW-9.3 ppg ECD-10.95 ppg Max gas-236 units.
Wiper tripped on elevators F/3497'-T/2465' w/ no issues. Had calculated hole fill. P/U-90K S/O-69K
Serviced rig- Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive line. Inspected saver-sub (ok).
RIH on elevators F/2465'-T/3497', washing last std. down. Had calculated pipe displacement. P/U-75K S/O-53K.
Cont. directional drilling 6.75" production hole F/3497' to current depth of 4123'. Pumped 20 bbl sweep at 3504', sweep came back on time with a 100% increase in
cuttings. P/U-90K S/O-65K ROT-75K GPM-290 SPP- 2081 psi Diff- 300 psi RPM-60 TQ-6.5K WOB-7K MW-9.4 ppg ECD-10.79 ppg Max gas- 317 units. Distance to well
plan: 7.72' 2.95' Low 7.14 Left
Report Number
9
Report Start Date
1/27/2025
Report End Date
1/28/2025
Operation
Continue Drilling 6 3/4'' hole section f/ 4123' t/ 4811' 275 gpm 2079 psi 60 rpm 7.3k tq on bottom, 9.4 ppg 11.04 ppg ECD, Max gas 584 units PUW 105k SO 74k 87k ROT
CBU obtain SPRs and survey, flow check well static slight seepage loss, blow down top drive.
Make wiper trip f/ 4811' t/ 1369' no hole issues pulling on elevators.
Service rig and top drive, inspect brake linakge and drive line, grease croen and draw works
P/U and singled in the hole w/ 4.5" DP (107 jts.) F/1369'-T/4699', set down 15K, unable to pass. M/U TDS, broke circ. Washed/Reamed F/4699'-T/4811'. GPM-276
SPP-1906 psi RPM-40 TQ-6.5K MW-9.4 ppg ECD-10.73 ppg.
CBU, max gas- 970 units. Hole unloaded at BU. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back on time w/ a 25% i ncrease in cuttings.
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169
Page 3/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Cont. directional drilling 6.75" production hole F/4811' to current depth of 5063'. P/U-120K S/O-81K ROT-95K GPM-278 SPP- 2092 psi Diff- 355 psi RPM-60 TQ-7.5K
WOB-6K MW-9.4 ppg ECD-10.91 ppg Max gas- 387 units. Dista nce to well plan: 8.19' 5.96' Low 5.61' Right.
Report Number
10
Report Start Date
1/28/2025
Report End Date
1/29/2025
Operation
Continue Drilling 6 3/4'' Hole Section f/ 5063' t/ 5817' 275 gpm 2120 psi 60 rpm 8.8k tq on bottom, 5k WOB, 9.45 ppg MW 10.78 ppg ECD, Max gas 755 units, 135k PUW
87k SOW 106k ROT
Circulate bottoms up, obtain survey and SPR's, Flow check well static
Make wiper trip f/ 5817' t/ 4752' with no issues
Service rig and top drive, inspect and grease draw works, grease crown and blocks.
RIH f/ 4752' t/ 5817' without issues, wash last stand to bottom, Pump Hi Vis Sweep around.
Resume Drilling 6 3/4'' Hole Section f/ 5817' t/ 6191' 275 gpm 2390 psi 60 rpm 9.4k tq on bottom, 5-7k WOB, 9.45 ppg MW 10.82 ppg ECD, Max gas 250 units, 142k
PUW 93k SOW 113k ROT
Pumped 20bbl hi-vis sweep at 5817'. Sweep back 5.7bbl early with a 50% increase in cuttings.
Cont. Drilling 6 3/4'' Hole Section f/ 6191' t/ 6443' 275 gpm 2390 psi 60 rpm 9.4k tq on bottom, 9k WOB, 9.45 ppg MW 11.18 ppg ECD, Max gas 250 units, 145k PUW 94k
SOW 114k ROT
Pump 20bbl sweep at 6334' back 5.7 bbl early with 50% increase.
Report Number
11
Report Start Date
1/29/2025
Report End Date
1/30/2025
Operation
Continue Drilling 6 3/4'' Hole section f/ 6443' t/ 7006' 275 gpm 2130 psi 60 rpm 10.7k tq on bottom WOB 7-10k MW 9.4 ppg ECD 10.76 ppg Max Gas 523 units, 155k PUE
105k SOW 124k Rot
Circulate botoms up, obtain survey and SPR's, flow check well stataic
Make wiper trip f/ 7006' t/ 5787' with no issues
Service rig and top drive, grease crown and blocks, inspect draw works and brake linkage
RIH f/ 5787' t/ 7006' wash last stand to bottom, pump hi vis sweep around, set down had to wash and ream f/ 6390' t/ 6430'
Resume drilling 6 3/4'' hole section f/ 7006' t/ 7223' 275 gpm 1950 psi 60 rpm 10.8k tq on bottom WOB 7-10k MW 9.4 ppg ECD 10.81 ppg Max Gas 826 units, P/U-157k
S/O-101k ROT-124k.
At 7223' lost all returns. Fluid not visible in the stack.
Pump hi-vis sweep at 7006'. Back on time with a 30% increase in cuttings.
Pump OOH t/ 7006' while building LCM pill. Experiencing differential sticking, having to idle the pump and rotate to break string over. Able to get hole full idling pump and
turning hole fill on by 7006'. Spot 60lb/bbl LCM pill at 111GPM=400-600PSI 25RPM=9.4K Tq with varying return flow 0-10%.
Lost 160bbl from 22:30 to 00:00.
POOH f/7006' t/6005'. Taking 35-50k overpull to break string over coming out of slips.
Pump and spot 20 bbl 60lb/bbl LCM pill at 6005
POOH on elevators f/6005' t/5438' 15-25k overpull to break string over. P/U-145k, S/O-85k. Pull tight at 5438' not able to work through. BROOH f/5438' t/5189'
150GPM=820PSI 30RPM=7.8k Tq
Circulate while building surface volume. 110GPM working up to 150GPM 595 to 830PSI, 20RPM=7.7k Tq. At BU 992 units of gas.
Total losses down hole 183bbl.
Report Number
12
Report Start Date
1/30/2025
Report End Date
1/31/2025
Operation
Continue Building volume and working pipe.
RIH f/ 5189' t/ 7133' set down wash and ream to 7218' Lost all returns continue Reaming t/ 7223'
Drill f/ 7223' t/ 7257' without returns 200 gpm 1850 psi 60 rpm 8k WOB 150k PUW 110k SOW 125k ROT
BROOH f/ 7157' t/ 7159' with no returns, 20-30k over pulls, eratic torque, regained partial returns max gas seen 1423 units, 300 bbls lost total
Pump 20 bbl 60lb/bbl LCM pill spot out side bit, POOH t/ 6950' attempt to circulate no returns pump second 20 bbls LCM Pill spot out side bit
POOH f/ 6950' t/ 5324' calculated fill 11.5 bbls actual fill 17.7 bbls
Monitor well on trip tank while moving pipe, static loss rate 1.7 bph
POOH on elevators f/ 5324' t/ 3504'. Working through multiple tight spots on elevators starting at 4752' (10k-50koverpulls) P/U-130k, S/O-65k.
Pulled tight at 3504' (50k over) not able to work through. M/U top drive and BROOH f/3504' t/2403'. 155GPM=770PSI, 30RPM=5.2-8.8k TQ. Varrying pulling speed 15-60
ft/min to mitigate torqe spikes and packoffs.
Cont BROOH f/2403' t/1551'. 250GPM=1250PSI, 40RPM=3.8-5.9k TQ. Varrying pulling speed 15-60 ft/min to mitigate torqe spikes and packoffs.
Able to POOH on elevators f/1551' t/680'. Observed 10-25k drag which fell off after pulling into the shoe at 1442'. P/U-50k, S /O-47k.
Rack back HWDP and Jar stand. PJSM, remove sources from MWD tools. Plug into MWD tools and download recorded data. L/D BHA.
Report Number
13
Report Start Date
1/31/2025
Report End Date
2/1/2025
Operation
Finish L/D BHA bit graded 1-1 in gauge clean and clear floor
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169
Drill f/ 7223' t/ 7257' without returns
g
Total losses down hole 183bbl.
gyp
Lost 160bbl from 22:30 to 00:00.
Lost all returns continue Reaming t/ 7223
Taking 35-50k overpull to break string over coming out of slips
At 7223' lost all returns
Page 4/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
M/U Bit and BIt Sub, RIH w/ HWDP t/ 1369'
Slip and cut Drilling line 62' service rig and top drive, change saver sub and grabber dies on top drive.
RIH f/ 1369' t/ 7200' had to work through tight spot
@ 6450'
Attempt to break circulation, DP pressuring up 2500 psi not bleeding off, attept to get circulation unable, suspcet ice plug, blow down top drive.
POOH f/ 7200' t/ 5314' checking every ten stands for circulation with no sucess. Cont POOH f/5314' t/4056' attempt to circulate again. Cont t/ POOH t/1552' screw in and
try to circulate again with no luck. POOH f/1552' t/ 497'.
Rack back 6 stands of HWDP. Connection between HWDP stand 2 and 3 packed off with clay. L/D HWDP joints 4, 3, and 2. Pulled up to bit and found bit, bit sub, XO,
and 5' up into HWDP joint 1 packed tight with clay.
Cleaned Clay out of HWDP, bit, bit sub and XO. Cleaned and cleared rig floor.
P/U Cement BHA. M/U bit, bit sub, and XO. P/U and RIH with 4 jnts of HWDP that were laid down. Cont to RIH with 6 stands of HWDP from derrick. Screw in and pump
string volume to ensure BHA is clear.
Cont to RIH out of derrick w/ DP f/497' t/5508'. Pumping string volume every 15 stnads to ensure pipe is clear of debris.
Report Number
14
Report Start Date
2/1/2025
Report End Date
2/2/2025
Operation
Continue RIH f/ 5508' t/ 7139' Filling pipe and breaking circulation every 1000'
Wash and ream down f/ 7139' 't/ 7257' lost returns @ 7221' Max gas observed before losses 2048 units
R/U cementers, fill and PT lines 1500 psi, pump 62 bbls 15.3 ppg cement w/ fiber in first 20 bbls @ 3 bpm 0 psi Displace cemetn w/ 91 bbls of mud with annular shut 0 psi
until last 3 bbls then pressure rose t/ 200 psi and bled down after pumps wer shut down.
R/D cement lines, POOH f/ 7197' t/ 6600', had to P/U E Kelly to break over down over pulling 60k up
Break circulation pump 20 bbls walnut pill, flush pipe, 250 gpm 460 psi with full returns.
Monitor well on trip tank while moving pipe while waiting on cement, Cementers returned to shop to batch and load 60 bbls of 15.3ppg cement.
RIH on elevators f/6600' t7123' set down 10k. Tag cement at 7123'.
Wash and ream f/7123' t/7257'. 240GPM=600PSI, 60RPM=9.6K, 3-10kWOB, 17% return flow. Seen a reduction in return flow at 7216'. Flow slowly dropped from 17%
down to 6% then back up to 13%. 120bbl/hr dynamic loss rate.
Rack back one stand. Parked at 7196' R/U TIW, side entry sub, and Fox energy cemnters. Monitor well on trip tank- Static loss rate 8bbl/hr slowing to 4.6bbl/hr.
Pump 2 bbl ahead shut in and PT lines to 1700PSI. Pump 63 bbl of 15.3ppg cement at 3bbl/min 370psi to 90spi LCM in first 20bbl. Close annular close annular and
displace with 70.5 bbl of 9.45ppg mud at 3bbl/min starting at 20psi. At 46bbl into displacement pressure jumped to 270psi at 3bbl/min. Stopped displacement at 70bbls.
Pressure was 890psi at 0.5bbl/min. Bled 4bbl back to the truck. 44bbl of mud was lost duing the job. Appoximately 35bbl of cement was injected into formation, with
25bbl left in open hole. Break down cement assembly. R/D and wash up cementers.
POOH on elevators f/7193' t/6158'. Observed 15-25k overpull to break string over. P/U-165k, S/O-113k.
Pump 20bbl hi-vis walnut sweep to clean the DP. Circulate at 240GPM=475PSI with full returns.
Flow check well-static. Blow down surface lines. POOH f/6158' t/2937'.
Report Number
15
Report Start Date
2/2/2025
Report End Date
2/3/2025
Operation
Continue POOH f/ 2937' t/ surface L/D Bit and Bit sub
Flush stack with black water, function rams and annular.
Service rig and top drive, inspect brakes and drive shaft, grease crown and blocks, clean suction screens on mud pumps.
Make up tripple combo BHA as per DD/MWD, upload MWD and shallow test tools, Load sources, RIH w/ remaining BHA f/ derrick.
RIH f/ 680' t/ 1300'
Slip and cut 44' of drilling line.
RIH f/ 1300' t/ 6344'. P/U-155k, S/O-95k. Tag cement at 6344'.
Drill out cement f/6344' t/7073'. 270GPM=2180PSI, 80RPM=11.6k TQ, 5-7k WOB. M/W 9.45ppg.
Cont to drill out cement f/7073' t/7257'. 270GPM=2200PSI, 80RPM=12.1k TQ, 5-7K WOB, MW 9.4ppg. No drop in flow or losses were observed at loss zone of 7223'.
Drill ahead f/7257' t/7287' to ensure no losses were observed before displacing the cement contaminated drilling fluid. 220GPM=1700PSI, 60RPM=11.9k TQ, 7-8kWOB,
MW 9.4ppg, ECD 10.17ppg,
CBU. Pump 20bbl spacer and displace 300bbl of cemented contaminated mud. 170GPM=930PSI
Cont drilling ahead f/7287' t/7382'. 230GPM=1520PSI, 60RPM=10.8k TQ, 6-10kWOB, MW 9.45, ECD 10.19ppg, Max Gas 168 units. P/U-177k, S/O-103k,ROT-127k.
Drilling ahead with reduced parameters to prevent re-fracturing loss zone.
Report Number
16
Report Start Date
2/3/2025
Report End Date
2/4/2025
Operation
Continue Drilling Production hole f/ 7382' t/ TD @ 7950' 225 gpm 1366 psi 60 rpm 10.6k tq on bottom, 6-10k WOB, Max Gas 592 units, MW 9.45 ppg ECD 10.24 ppg,
180k PUW 120k SOW 145k ROT
Circulate bottoms up, obtain survey and SPR's, Flow check well static.
Make wiper trip f/ 7950' t/ 7258' with no issues, slight over pull coming out of the slips 20-30k
RIH f/ 7258' t/ 7950' no issuse
Pump a 20bbl Hi Vis sweep around at 7950'. Sweep back 200 strokes late witha 25% increase in cuttings.
POOH on elevators f/7946' t/2445' seeing some 10-40 overpull coming out of slips unitl 4200'. P/U-183k, S/O-103k.
Cont. to POOH on elevators f/2445' t/680' without issue.
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169
Wash and ream down f/ 7139' 't/ 7257' lost returns @ 7221' Max gas observed before losses 2048 units
Pump 63 bbl of 15.3ppg cement at 3bbl/min 370psi to 90spi LCM in first 20bbl
Page 5/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
Rack back 4 stands of HWDP and L/D jar stand. PJSM and remove sources from Nuke tools. Download MWD data. L/D directional BHA as per Sperry. Bit graded:
1-1-CT-A-X-1-WT-TD
Service and insperct crown, derrick,topdrive, saver sub and iron roughneck. Grease and adjust brake linkage.
R/U Parker TRS casing equipment. R/U fill up line. Stange centralizers and liner.
Report Number
17
Report Start Date
2/4/2025
Report End Date
2/5/2025
Operation
Held PJSM with rig crew and casing crew, PU and MU 3 1/2" shoe track and checked FE (good). Cont to PU single in hole with 3 1/2" Wedge 563 L-80 9.2# liner, torqued
to 3500 ft/lbs to 1396' (just above surface shoe). MU XO and topdrive.
CBU at 3 bpm. Removed topdrive and blew down.
Cont PU single in open hole from 1396' to 4785', MU XO and topdrive.
CBU staging up to 166 gpm-329 psi. Max gas at bottoms up 84 units. Removed and blew down topdrive.
Cont PU single in hole from 4785' to 6687', down wt 50K.
Cont transporting excess 6% KCL mud to upright tanks at Paxton pad and cleaning tank bottoms.
PU and MU 3 1/2" x 7 5/8" Yellow Jacket liner hanger assembly, mixed and poured xanplex, PU 2 jnts of 4 3/4" DC, MU topdrive, pumped one string volume staging up to
4 bpm, 454 psi. Removed and blew down topdrive.
Cont to P/U and single in hole w/ 30 4-3/4" DC (32 total) on top of liner hanger. Cross over to HWDP set down 10k at 7737'. Screw in and wash down f/7737', tagged
bottom at 7950'. P/U-116k, S/O-96K.
CBUx2 to condition mud for cement job. Stagged pumps up to 4bbl/min 680PSI, Max gas 160 units, P/U-119K, S/O96K. R/U Fox energy cementers.
Fox pumped 2.5 bbls water to flush and fill lines. Shut in at YJ cement head and PT lines at 1300 psi low, 4630 psi high. Good tests. Lined up YJ cement head to Fox
unit, pumped 33.4 bbls 11 ppg FMP300 Spacer at 2.5 bpm- 340 to 320 psi, followed with 217 bbls out of the 279bbl to be pumped Class G Lead cement at 2.5 to 3
bpm-260 to 100 psi.
Report Number
18
Report Start Date
2/5/2025
Report End Date
2/6/2025
Operation
Pumped the last 61 of 278 bbls (743 sx) 12.5 lead cement at 2.5 to 3 bpm-260 to 550 psi, followed with 24 bbls (109 sx) 15.3 ppg Class G Tail cement at 2.4 bpm-550 to
490 psi, return flow reduced from 10% to 1 to 8%. 9 bbls into Tail started overboard spacer. Had no LCM in lead or tail cement. YJ released dart, Fox then displaced with
9.5 ppg 6% KCL mud at 2 bpm-500 to 1570 psi. 30 bbls into displacement had cement to surface. With 10 bbls to go, reduced rate to 1 bpm-1800 psi and parked hanger
on depth at 140K, seeing slight returns. Bumped plug on landing collar 64 bbls into displacement (calculated at 64.7 bbls). FCP 1800 psi. Fox increased to and held 2050
psi (250 over fcp) for 3 minutes, bled back 1/2 bbl to truck and floats held. CIP at 08:21 on 2-5-25. Lost 23 bbls during the j ob. Could not rotate due to low liner pipe MU
torque. Did reciprocate until 7 bbls into displacement. Increased pressure to 2400 psi, slacked off on blocks from 145K to 75K, P/U to 140K with no indication of release.
Slacked off to 40K and increased pressure to 4090 psi seeing pusher tool function at 2830 psi, string weight dropped to 38K, at 3780 psi string jumped, bled off pressure,
PU and have free travel at 60K. PU 8’ to release dogs, rotated at 3 rpm and set down on liner top to 15K twice more, to ensure packer set.
R/D cmt hose and L/D YJ cmt head. M/U TD to stump to circulate. Pressured up to 1050 psi on drill string, PU 5’ and pressure dumped. CBU x3 at 315 gpm-422 psi. Had
total 33.4 bbls spacer and 66 bbls cement to surface throughout the job. RD and released Fox cementers. Blew down topdrive and L/D single HWDP jnt.
POOH racked back 3 stands HWDP, then cont POOH L/D 32 jnts 4 3/4" DC's. Inspected, broke down and L/D running tool. Neutralizer ring shear screws were sheared.
PU kelly joint and MU diffuser, drained stack and flushed same with black water. L/D diffuser and joint.
PU YJ PBR polish mill assembly, RIH to 1219', up wt 43K, dwn wt 43K. MU topdrive and broke circ at 225 gpm-403 psi, S/O and tagged liner top at 1226'. PU 3', rotated
at 4 rpm-2531 ft/lbs torque, eased down and dressed liner top as per YJ Rep with .4K wob and 2780 ft/lbs torque. PU 20' and parked.
Held PJSM, pumped 20 bbls hi-vis spacer followed with IFW and cont to circ until clean at shakers. Monitored well for flow for 30 minutes (static). Staged thread
protectors and CCI for vac wiper balls.
Sent AOGCC 24 hr notice for MIT's.
POOH from 1237' L/D DP, CCI vacuumed wiper balls, cleaned and dried threads and installed thread protectors on pipe rack.
RIH out of derrick and L/D 2200' of DP in 1000' increments. Pumping a string volume each time to flush the pipe.
P/U cement head and break off pups and XO's.
RIH out of derrick and L/D 3036' of DP in 1000' increments. Pumping a string volume each time to flush the pipe.
Report Number
19
Report Start Date
2/6/2025
Report End Date
2/7/2025
Operation
Cont RIH, circ string volume then POOH LD 4 1/2" DP in 1000' increments.
Pulled wear ring, MU cactus brush tool on topdrive, flushed and brushed hanger profile in wellhead, LD single jnt and brush tool, blew down topdrive.
RU test equipment to mezz kill, flooded stack, choke line and choke manifold, functioned rams to clear any air from cavities, closed blind rams.
Pumped 49.35 gallons to achieve 3080 psi on chart and held 30 minutes. Lost 65 psi over 30 minutes. Found drip on lower ram door seal. Bled back 48.4 gallons. Once
bled off checked ram door bolts for tight.
Pumped 50.4 gallons to achieve 3190 psi on 7 5/8" x 3 1/2" casing/liner lap. Held 30 minutes. Lost 53 psi over 30 minutes. Could find no leaks. Bled back 50.4 gallons.
Scanned chart and sent to Drilling Manager, decision made to run DLH packer on completion string. RD test equipment.
(RU tubing tongs and handling equipment, shipped out cement silo and upright water tank between tests)
Held PJSM with rig crew, tong operator and YJ Rep. PU 10' 4" seal assembly on full jnt tubing, PU DLH packer assembly, cont PU single in hole with 3 1/2" 8rnd L-80
tubing torqued to 3200 ft/lbs and RIH to 1180', MU XO and topdrive, circulated 6% KCL inhibited brine around, cont PU single in hole total 39 jnts tubing and tagged
no-go. LD two jnts, PU landing joint/hanger assembly, MU 22.45' of spaceout pups, drained stack, landed hanger putting no-go 1.32' off seat. Set lock ring as per
wellhead Rep and pull tested to 40K.
RU test equipment on tubing, flood and purge. Perform MIT-T to 3000PSI-good test. Pumped 0.65bbl bled back 0.65bbl. R/U test equipment on IA and perform MIT-IA to
3000PSI-good test. PUumped 0.5bbl bled back 0.5bbl. R/D test eqipment.
WHR set two way check. Flush surface lines and equipment with Barakleen pill. Blow down same.
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169
gp
decision made to run DLH packer on completion string
Page 6/6
Well Name: NINU Kalotsa 10
Report Printed: 3/20/2025WellViewAdmin@hilcorp.com
Well Operations Summary
Operation
De-energize accumulator. Opened ram doors, clean and inspect components. Perform EAM on rams, ram doors, ram seals, bonnets and shafts. Change out sealing
rubbers on UPR's and door seal on LPR's. Remove chains, flow line and riser from BOP. Install shipping beams. Remove choke and kill lines from each side of mud
cross. Buttom up ram doors and bleed down accumulator. Clean and prep for rig move.
Report Number
20
Report Start Date
2/7/2025
Report End Date
2/8/2025
Operation
Unbolted and removed cap off annular, replaced sealing element and re-installed cap. RU and removed BOP stack and spacer spool from wellhead, spotted CCI crane
and transfered stack from celler to cradle. Cont to load and ship out variouos equipment to Paxton pad and HVB pad.
Staged, RU and installed dry hole tree on wellhead. Wellhead Rep tested tree and flange at 5,000 psi for 10 minutes, good test, removed 2 way check. vac'd out brine
from tubing and capped with 20' diesel.
Cont going through mud pumps, mechanic changed out air compressor on floor motor, replaced suction rubbers in pits, undressed rig floor, checked endplay on topdrive
quill, layed over poorboy degasser and removed vent pipe, cont loading and shipping assorted equipment.
Pressure wash derrick, iron rough neck and top drive. R/D all 3rd party shacks. R/D gen 3. Clean pump house. Add oil to all agitators. R/D Pason wires on pits. R/D mud
pits and mud transfer lines. Chang out valves on fill up line.
PJSM, R/D and L/D top drive. Remove T-Bar and prep derrick to scope down. R/D choke line from choke house. R/D top drive HPU hydraulix lines. Work on EAM's.
Install shipping pin in iron roughneck and R/D controls.
Report Number
21
Report Start Date
2/8/2025
Report End Date
2/9/2025
Operation
Spooled up electric and Pason cords, stored gas alarms and sensors, secured koomey hoses, blinded off all plumbing flanges and hoses for road travel, prepped/held
PJSM/scoped down mast laying down lower torque tube, spooled off drill line and secured to derrick.
Removed centrifuge from stand and clam shell off rig floor with crane, held PJSM and lowered mast onto carrier, secured kelly hose and service loop to derrick,
dis-connected hydraulics from derrick to sub, RD brake linkage, serviced rotary table drain fitting, cont loading floats with available equipment.
Fold up v-door and R/D catwalk. R/D camera system from dog house, pump room and shakers. Disconnet electrical lines and R/D Top drive HPU. Winterize mix pumps
and liner wash pumps. Disconnect hydraulics hoses from choke house. Winterize test pump. Remove handi-berm containment around rig.
Blow down and R/D steam, air and water lines. R/D tarps. Clean out rig water tank. Cont. to R/D electrical lines and cover plug ends. Perform mast inspection.
Rig Released at 06:00.
Field: Ninilchik (NINU)
Sundry #: 224-147
State: ALASKA
Rig/Service: HEC 169
Page 1/2
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-20732-00-00 Field Name:Ninilchik (NINU)State/Province:ALASKA
Permit to Drill (PTD) #:224-147 Sundry #:325-061 Rig Name/No:
Jobs
Actual Start Date:2/10/2025 End Date:
Report Number
1
Report Start Date
2/11/2025
Report End Date
2/11/2025
Last 24hr Summary
PTW/PJSM. SITP 0 psi. MIRU YJ E-line. RIH w/ CBL tool string and tag @ 7,881'. Log up pass @ 50 fpm to 884'. Estimated TOC @ 1,224' (liner top @ 1,222').
RDMO YJ E-line.
Report Number
2
Report Start Date
2/16/2025
Report End Date
2/17/2025
Last 24hr Summary
Complete PJSM / PTW. N/U BOPE stack. Spot CTU, N2 pump, and N2 transport. BOPE test 250 psi low / 3000 psi high as per sundry. Sent AOGCC test notification
2/15/25, left Jim Regg voice message this morning before starting test. No reply. R/U N2 pump and coil pump. SDFN.
Report Number
3
Report Start Date
2/17/2025
Report End Date
2/18/2025
Last 24hr Summary
Complete PJSM / PTW. MIRU Fox CTU 10. M/U BHA = checks, stinger, and 2.125" DJN. Shell test 250 psi / 3000 psi. RIH w/BHA. Tagged PBTD @ E - 7,907' ctm / M -
7,895' ctm. Circulate STS w/95 bbls of FW. Returns clean after 6% KCI was displaced from well. Blow well dry w/N2. Pumped 119,000 scf (1278 gallons). Total fluid
returns = 86 bbls. Calculated CV + CTBS = 82 bbls. Pooh w/BHA. Pressure up tubing to 2500 psi w/N2 for Eline and secure well (333 gallons of N2). RDMO Fox CTU 10.
Travel to KGF.
Report Number
4
Report Start Date
2/19/2025
Report End Date
2/19/2025
Last 24hr Summary
PTW/PJSM. 2,320 psi SITP. MIRU YJ E-line. PT lubricator to 3000 psi - good test. RIH w/ GPT and tag @ 7,881' and find fluid level ~ 7,750'. RIH w/ 20' x 2 3/8" 5 SPF
60 DEG guns, bleed well pressure to ~2000psi, and perf TY_140 Lower (7,810’-7,830’). RIH w/ 14' x 2 3/8" 5 SPF 60 DEG guns and perf TY_140 Lower (7,796’-7,810’).
Secure well, SDFN.
Report Number
5
Report Start Date
2/20/2025
Report End Date
2/21/2025
Last 24hr Summary
PTW/PJSM. WHP 2067 psi. MIRU YJ E-line. PT lubricator to 3000 psi. RIH w/ GPT, tagged 7,881' elm. See FL @ 7,500'. Discuss plan forward. Set 2.75" CIBP @
7,788' elm. WHP 2027 psi. Perforate TY_140 sands 7,752' - 7,783'. No WHP change over 15 min. Bleed WHP in 300 psi increments @ 5 psi/min.
Report Number
6
Report Start Date
2/22/2025
Report End Date
2/23/2025
Last 24hr Summary
PTW/PJSM. WHP 1300 psi. RU YJ Eline. RIH w/ GPT and tag @ 7,777', see fluid level @ 7,220'. Discuss plan forward w/team. Standby for N2 crew. RU Fox N2 pump.
PT lines to 5K psi and pressure up well from 1220 psi to 4500 psi, no injectivity. Pumped 87K SCF (940 gals) N2. Secure well, SDFN.
Report Number
7
Report Start Date
2/23/2025
Report End Date
2/24/2025
Last 24hr Summary
PTW/PJSM. WHP 4250 psi. RU YJ Eline. Bleed WHP to 3100 psi for grease control. RIH w/ GPT, tagged 7,777', fluid level @ 7,685'. Set 2.75" CIBP @ 7725'. Perforate
TY_118 interval 7,582' - 7,640'. SDFN. Bleed N2 off well. Flow test.
Report Number
8
Report Start Date
2/24/2025
Report End Date
2/25/2025
Last 24hr Summary
PTW/PJSM. WHP 800 psi. RU YJ Eline. RIH w/ GPT, tagged plug 7,725', fluid level @ 7,380'. Discuss plan forward w/OE. Set 2.75" CIBP @ 7,634' (hung up on
correlation pass). Rehead & redress MSST. Set CIBP above TY_118 interval @ 7,560'. Dump 4 gallons cement on top of CIBP (10'). TOC = 7550'. SDFN.
Report Number
9
Report Start Date
2/25/2025
Report End Date
2/26/2025
Last 24hr Summary
PTW/PJSM. WHP 650 psi. MIRU YJ Eline. Made 4 gun runs w/2-3/8" guns (5 spf, 60 deg). Perforated TY_90 sands: 7339'-7349', 7324'-7330', 7310'-7316', 7273'-7293',
7228'-7246' (bottom 6ft of gun did not shoot). Discuss plan forward w/OE. Perforate TY_90 7213'-7223', 7202'-7208'. SDFN, Ops to flow well.
Report Number
10
Report Start Date
2/26/2025
Report End Date
2/27/2025
Last 24hr Summary
PTW/PJSM. WHP 108 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. Ran GPT and tagged TOC @ 7551', see FL @ 7046'. Set CIBP @ 7170'. MIRU Fox
N2 pump. Pressure up tubing to 2054 psi with N2. Pumped 67 mscf (720 gallons). Perforated TY_67 interval 6824'-6836'. SDFN. Ops to flow well.
Report Number
11
Report Start Date
2/27/2025
Report End Date
2/28/2025
Last 24hr Summary
PTW/PJSM. WHP 108 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. Ran GPT, logged FL @ 6985'. Discuss plan forward w/OE. Fox pressured up tubing to
326 psi. Perforated TY_65 6755' - 6785'. Gun wet. Pressured up tubing w/N2 to 1250 psi and see breakover. Set CIBP @ 6720'. Pressure up tubing to 1450 psi w/N2.
Total N2 pumped 83 mscf (891 gallons). Perforated TY_53 6540' - 6567'. SDFN.
Report Number
12
Report Start Date
2/28/2025
Report End Date
3/1/2025
Last 24hr Summary
PTW/PJSM. WHP 1422 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. WHP = 1422 psi. YJ made 2 gun runs but was uable to get 2-3/8" x 12' gun to fire.
RDMO YJ Eline and re-spot equipment to allow line heater access to Kalotsa 9. SDFN.
Report Number
13
Report Start Date
3/1/2025
Report End Date
3/2/2025
Last 24hr Summary
PTW/PJSM. WHP 1422 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. WHP = 1440 psi. Made 4 gun runs w/2-3/8" guns (5 spf, 60 deg). Perforated Lwr
TY_43 6057'-6069'. Perforated Upr TY_43 6026'6049'. Perforated Lwr TY_37 5856'-5864'. Perforated Upr TY_37 5814'-5839'. SDFN.
Page 2/2
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Report Number
14
Report Start Date
3/3/2025
Report End Date
3/4/2025
Last 24hr Summary
PTW/PJSM. WHP 400 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. Shoot FL w/Echometer = 5374'. Ran GPT, found FL @ 5332'. Jump gas from Kalotsa
9 to Kalotsa 10 and push fluid down to 5440' in 2 hrs. SDFN. Let Kalotsa 9 jumper hose to Kalotsa 10 go through the night. Will shoot FL in the morning.
Report Number
15
Report Start Date
3/4/2025
Report End Date
3/5/2025
Last 24hr Summary
PTW/PJSM. WHP 1350 psi. MIRU YJ Eline, PT PCE to 250 psi low / 3000 psi high. RIH w/GPT, log FL @ 5350'. MIRU Fox N2 pump. Pressure up tubing w/N2 to 3000
psi, logged FL w/GPT @ 5650'. Set 2.75" CIBP @ 5795'. Perforated Lwr TY_18 5609'-5636', Upr TY_18 5565'-5571', Lwr TY_17 5542'-5548'. SDFN. Ops to bleed WHP
to 250 psi.
Report Number
16
Report Start Date
3/5/2025
Report End Date
3/6/2025
Last 24hr Summary
PTW/PJSM. Shoot FL with Echometer - 5,684'. Perforate TY_17 Sand from (5,524' - 5,532'), (5,512' - 5,518'), (5,477' - 5,504'), (5,454' - 5,474'), (5,438' - 5,454') with well
shut-in. Turn well over to Production Ops to flow test.
Report Number
17
Report Start Date
3/6/2025
Report End Date
3/7/2025
Last 24hr Summary
PTW/PJSM. Shoot FL with Echometer - 5,605'. Perforate TY_16 Sand (5,405' - 5,413'), TY_15 Sand (5,322' - 5,327'), TY_15 Sand (5 ,301' - 5,311'), TY_14 Sand (5,251' -
5,257') with well shut-in. Shoot FL with Echometer - 5,597'. SDFN and turn well over to Production Ops to flow test.
Report Number
18
Report Start Date
3/7/2025
Report End Date
3/8/2025
Last 24hr Summary
PTW/PJSM. Shoot FL with Echometer - 5,077'. Run flowing GPT survey. Perforate TY_11A Sand (4,845' - 4,850'), TY_10B Sand (4,738' - 4,743'), TY_10B Sand (4,707' -
4,713'), TY_9A Sand (4,626' - 4,646'), TY_8 Sand (4,528' - 4,542'), TY_7 Sand (4,504' - 4,516'), TY_7 Sand (4,459' - 4,473') with well shut-in. SDFN and turn well over to
Prod Ops to flow test.
Report Number
19
Report Start Date
3/8/2025
Report End Date
3/9/2025
Last 24hr Summary
PTW/PJSM. Dump bail 25' of cement on top of CIBP at 5,790'. Perforate TY_6 Sand (4,370' - 4,376'), TY_6 Sand (4,323' - 4,341'), TY_5B Sand (4,295' - 4,301'), TY_5A
Sand (4,256' - 4,262'), TY_5 Sand (4,200' - 4,207'), TY_5 Sand (4,178' - 4,184'), TY_3 Sand (4,066' - 4,077'), TY_3 Sand (4,057' - 4,064') with well shut-in. RDMO YJ
E-line.
Page 1/1
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025
WellViewAdmin@hilcorp.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
7,950.00 Original KB/RT Elevation (ft):
144.10
RKB to GL (ft):
18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Surface Run Date:
1/24/2025 Set Depth (ftKB):
1,422.65
Casing Weight on Slips (1000lbf):
32,000.0 Pick Up Weight (1000lbf):
50,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
2.50 Ft/Min (ft/min):
9.48
Run Job:
251-00002 Kalotsa 10 Drilling, Drilling -
Drilling, 1/19/2025 06:00
Set Depth (ftKB):
1,422.65 Set Depth (TVD) (ftKB):
1,386.3
Centralizer Detail:
17
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Casing Hanger 11 6.87 1.30 22.30 21.00
1 Casing Pup Joint 7 5/8 6.87 29.70 L-80 3.10 25.40 22.30
32 Casing Joints 7 5/8 6.87 29.70 L-80 GBCD-BTC 1,311.39 1,336.79 25.40
Float Collar 8 1/4 6.75 1.45 1,338.24 1,336.79
2 Casing Joints 7 5/8 6.87 29.70 L-80 82.79 1,421.03 1,338.24
Shoe 8 1/4 6.75 1.62 1,422.65 1,421.03
Page 1/1
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025
WellViewAdmin@hilcorp.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 1,422.65ftKB
Wellbore
Original Hole
Job
251-00002 Kalotsa 10 Drilling, Drilling -
Drilling, 1/19/2025 06:00
Cementing Start Date
1/24/2025
Cementing End Date
1/24/2025
Top Depth (ftKB)
21.0
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
21.0
Bottom Depth (ftKB)
1,427.0
Top Measurement Method
Returns to Surface
Pump Start Date
1/24/2025
Cement in Place At
1/24/2025
Final Circulating Pressure (psi)
400.0
Plug Bump Pressure (psi)
900.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
39.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 10.50 59.0 4 Fox
Lead Slurry Lead G 210 12.50 78.0 5 Fox
Tail Slurry Tail G 173 15.30 38.0 4 Fox
Displacement Displacemen
t
9.00 61.0 5 Fox
Post Job Calculations
Subtype Value
Page 1/1
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025
WellViewAdmin@hilcorp.com
Casing
Siner
Welluore
Welluore Name:
Original Hole f otal bepth oTWelluore DTtK( B:7,950.00 ) riginal K( /Rf OleEation DTtB:144.10
RK( to v S DTtB:18.00 K( GCasing Llange bistance DTtB:K(Gf - uing Fanger bistance DTtB:
P( f bs
bepthDTtK( B:
Casing
Casing bescription:
Liner R- n bate:
2/4/2025 Het bepth DTtK( B:7,948.00
Casing Weight on Hlips D1000luTB:65,000.0 Pick Up Weight D1000luTB:125,000.0 ( lock Weight D1000luTB:15,000.0
MakeGUp Contractor:
Parker Casing N- muer Frs to R- n DhrB:18.00 Lt/Min DTt/minB:7.36
R- n Jou:
251-00002 Kalotsa 10 Drilling, Drilling -
Drilling, 1/19/2025 06:00
Het bepth DTtK( B:7,948.00 Het bepth DfVbBDTtK( B:7,678.4
Centralizer betail:
215
Attriu- te H- utype: Val- e:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Lloat Lailed?:
No
f est H- utype: Press- re DpsiB:
Casing D) r SinerBbetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
1 Liner Hanger 6.52 4.00 Ranger Hanger 35.49 1,261.49 1,226.00
1 Cross Over 5 1/2 2.99 17.00 VAM VAM 2.10 1,263.59 1,261.49
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 499.00 1,762.59 1,263.59
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.76 1,772.35 1,762.59
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 496.20 2,268.55 1,772.35
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.75 2,278.30 2,268.55
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.21 2,778.51 2,278.30
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.74 2,788.25 2,778.51
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.15 3,289.40 2,788.25
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.74 3,299.14 3,289.40
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.32 3,800.46 3,299.14
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.75 3,810.21 3,800.46
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.36 4,311.57 3,810.21
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.74 4,321.31 4,311.57
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 499.22 4,820.53 4,321.31
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.72 4,830.25 4,820.53
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.31 5,331.56 4,830.25
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.74 5,341.30 5,331.56
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.94 5,843.24 5,341.30
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.75 5,852.99 5,843.24
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 501.07 6,354.06 5,852.99
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.76 6,363.82 6,354.06
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 500.96 6,864.78 6,363.82
1 Liner Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.75 6,874.53 6,864.78
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 499.43 7,373.96 6,874.53
1 RA Pup Joint 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 9.75 7,383.71 7,373.96
16 Liner 3 1/2 2.99 9.20 L-80 Wedge 563 Wedge 563 498.50 7,882.21 7,383.71
1 Float Collar 3 1/2 Wedge 563 Innovex 1.67 7,883.88 7,882.21
2 Liner 3 1/2 2.99 9.20 L-80 IBT 62.25 7,946.13 7,883.88
1 Float Shoe 3 1/2 IBT Innovex 1.87 7,948.00 7,946.13
Page 1/1
Well Name: NINU Kalotsa 10
Report Printed: 3/21/2025
WellViewAdmin@hilcorp.com
Cement
Liner Cement
Type
Casing
Description
Siner Ceu ent
Ceu entef mtring
Sinerd, d142.665tKB
Wellbore
Original Hole
Job
- 0/ 96666- Kalotsa / 6 DrillingdDrilling 9
Drillingd /:/1:-6-06Eh66
Ceu enting mtart Date
-:0:-6-0
Ceu enting ( nf Date
-:0:-6-0
Top Dept) 75tKBM
/d--E.6
Cement Stages
Stage Number: 1
Description
Siner Ceu ent
Top Dept) 75tKBM
/d--E.6
Bottou Dept) 75tKBM
,d106.6
Top ReasPreu ent Ret) of
CBS
FPu p mtart Date
-:0:-6-0
Ceu ent in Flace At
-:0:-6-0
?inal CircPlating FressPre 7psiM
/d266.6
FlPg BPu p FressPre 7psiM
-d606.6
?Pll YetPrn%
Vo
YetPrns DPring Job 73 M
10
LolPu e to mPr5ace 7bblM
EE.6
LolPueSost7bblM
-N.6
BPu p FlPg%
kes
?loat ?ailef %
Vo
Fipe Yeciprocatef %
kes
Fipe Yotatef %
Vo
mlPrry Type Class Au oPnt 7sac³sM kielf 75tQ:sac³M Dens 7lb:galM
ActPal LolPu e
FPu pef 7bblM
CalcPlatef
LolPueFPupef
7bblM v AUg 7bbl:u inM FPu p x sef
Fre5lPs) 7mpacerM ?RFN66
mpacer
/ / .66 NN.4 NN.4 N ? oG( nergy
Seaf mlPrry Seaf 8 , 4N - ./ 6 / - .06 - , 2.6 - , 1.6 N ?oG( nergy
Tail mlPrry Tail 8 / 61 / .- N / 0.N6 - 4.6 - 4.6 - ?oG( nergy
Displaceu ent E3 KCS
RPf
1.06 E4.6 E4., - ?oG( nergy
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A
1
Gluyas, Gavin R (OGC)
From:McLellan, Bryan J (OGC)
Sent:Friday, March 7, 2025 4:15 PM
To:Scott Warner
Cc:Donna Ambruz
Subject:RE: Kalotsa 10 AOGCC 10-403 325-061 PTD 224-147 Approved 02-18-25
Scott,
Hilcorp has conditional approval to add the perfs listed in your email below as part of sundry 325-061.
Condition of Approval: Dump bail at least 25’ of cement on the CIBP set at 5795’ md before adding any
perforations not previously approved in the sundry 325-061.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Scott Warner <Scott.Warner@hilcorp.com>
Sent: Friday, March 7, 2025 11:25 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: Kalotsa 10 AOGCC 10-403 325-061 PTD 224-147 Approved 02-18-25
Bryan,
Hilcorp is requesting approval to perforate the following intervals now that plugs have been set in the well which has
reduced our MPSP therefore moving the depth higher for the shallowest allowable perf.
Zone Top MD
Bottom
MD
Top
TVD
Bottom
TVD Footage
TY_3 4057 4064 3821 7885 7
TY_3 4066 4077 3830 7907 11
TY_5 4178 4184 3941 8125 6
TY_5 4200 4207 3963 8170 7
TY_5A 4256 4262 4019 8281 6
TY_5B 4295 4301 4057 8358 6
TY_6 4323 4341 4083 8424 18
2
TY_6 4370 4376 4128 8504 6
Plugs have been set at the following depths:
7788
7725
7634
7560 – w/ 10’ of cement dump bailed on top
7170
6720
5795
All sands that were plugged off did not flow and were proven wet.
Deepest open perf is 5609’-5636’ MD or 5359’-5386’ TVD.
Applicable frac gradient: 0.7124 psi/ft using 13.73 EMW
Shallowest allowable perf: MPSP/(0.7124-.1) = 1821 psi/ 0.6124 psi/ft = 2,973’ TVD
Hilcorp will not perforate anything outside of the depths provided in the table above
Thank you,
ScoƩ Warner
Kenai – OperaƟons Engineer
Office: (907) 564-4506
Cell: (907) 830-8863
To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet.
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Monday, February 17, 2025 3:13 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>
Subject: RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Bryan,
Thanks for catching that I used the BHP instead of the MPSP.
So the correct math would be:
Applicable Frac Gradient: 0.7124 psi/ft using 13.73 ppg EMW
Shallowest Allowable Perf TVD: MPSP/(0.7124-0.1) = (3307-752 psi) / 0.6124= 4172‘ TVD
Prior to perforating shallower than 4215ft TVD (Ty_7), Hilcorp will provide data to AOGCC showing the BHP is less
than frac gradient of shallower perfs, or will have zones plugged off that may be at pressures above the frac
gradient of the sand.
3
Chad Helgeson
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, February 17, 2025 2:43 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>
Subject: RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Chad,
I think there’s an error in your calculation for shallowest allowable perf depth. You used BHP instead of MPSP. It
should be 2556 psi/0.6124 psi/ft = 4174’ TVD.
Let me know if you agree and I’ll update the 10-403.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Friday, February 14, 2025 3:35 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>
Subject: RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Bryan,
In the Perf sundry for Kalotsa #10 we requested perforating the Tyonek 3 Sand @ 3821 TVD to the Tyonek 140 sand
at 7517’ TVD.
I could not find a frac gradient curve for this field, but will keep looking. It should be noted that this part (structure)
of the Ninilchik field, most gas sands are depleted, which was confirmed with the reservoir pressure data that was
collected in January when we drilled Kalotsa #9. We did not collect pressure data for each sand that is proposed
to be perforated in Kalotsa #10, however it does show there are several sands that have current reservoir
pressures less than 0.1 psi/ft and several are at or below a 0.05 psi/ft. With these low pressure reservoirs Hilcorp
is confident that deeper sands at higher pressure will not frac shallower sands.
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.
4
To move forward with this request, I pulled all the FIT’s from Kalotsa drill wells, threw out the ones above 15ppg
and get an average FIT of 13.72 ppg. See table below.
Kalotsa well LOT
Well # FIT TVD Date
1 14.3 1380 12/21/2016
2 14.2 1379 2/6/2017
3 14.3 1316 6/12/2017
4 13.5 1410 5/20/2017
5 13.57 1071 9/27/2020
6 12.5 1258 9/24/2019
7 21.78 1389 10/26/2020
8 16.66 1662 2/12/2022
9 18.7 1382 1/6/2025
10 20.37 1386 1/25/2025
Average highlighted tests – 13.73 ppg
For purposes of this project if we use a 13.73 ppg Frac gradient and the deepest proposed perf open with a BHP of
3307 psi, the shallowest available perf will be at the T37 sand or 5400ft.
Applicable Frac Gradient: 0.7124 psi/ft using 13.73 ppg EMW
Shallowest Allowable Perf TVD: MPSP/(0.7124-0.1) = 3307 psi / 0.6124= 5400‘ TVD
Prior to perforating shallower than 5400ft TVD, Hilcorp will provide data to AOGCC showing the BHP is less than
frac gradient of shallower perfs, or will have zones plugged off that may be at pressures above the frac gradient of
the sand.
In the reservoir pressures collected on Kalotsa #9 the T90 Sand which is proposed to be the 5th zone perforated has
a bottom hole pressure in of 332 pisa to 408 psia with 3 different spots checked. The T3 sand has pressures of 247
psia.
Hilcorp will provide additional BHP data prior to perforating shallower than 5400ft TVD.
I will continue to look for a frac gradient plot to see if we can provide that to you to have confidence at other
depths.
Thanks
Chad Helgeson
Operations Engineer
Kenai Team
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, February 14, 2025 1:16 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
5
Chad, here’s what I sent to Scott
Sent from my iPhone
Begin forwarded message:
From: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov>
Date: February 12, 2025 at 3:49:00 PM AKST
To: Scott Warner <Scott.Warner@hilcorp.com>
Subject: Kalotsa 10 (PTD 224-147) Perf sundry
Scott,
The calculation for shallowest allowable perforation on the sundry application is based on an
extrapolation of the 20.3 ppg LOT pressure at the surface casing shoe at 1422’ TVD. This is an
unusually high frac pressure and although it seems that the formation strength at this casing
setting depth is repeatable over several nearby wells, I don’t think we can assume it extends to all
the sands down to TD.
Can Hilcorp provide a Pore-Pressure/Frac Gradient curve for this region? It could be based on
deeper leakoff tests on other nearby wells and any petrophysical data that you might have to help
get a more realistic picture of frac pressure vs. depth.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
6
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.
iU i,<Ja 1 _ WAsk_ 10
pTD 224 (4Za
Regg, James B (OGQ
From:
Brooks, Phoebe L (OGC)
Sent:
Tuesday, March 4, 2025 2:07 PM
To:
Rance Pederson - (C)
Cc:
Regg, James B (OGC)
Subject:
RE: Rig 169 MIT Test Report
Rance,
I changed the well name to Kalotsa 10 on the form and moved the "Waived" verbiage to the Notes. Please update your
copy.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.¢ov.
From: Rance Pederson - (C) <rpederson@hilcorp.com>
Sent: Friday, February 7, 2025 3:52 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>;
Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Subject: Rig 169 MIT Test Report
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Please see the attached MIT report for Kalotsa 10
Rance Pederson
Drilling Foreman
Ninilchik Unit
907-283-3169 office
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
Submit to: -mn reoaAalaska. oov.
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
AOGCCInseectorsdaisaka.aov ohoe0ebrookstsa1daska.00v
Hilcom Alaska LLC
South Kenai / Ninilchik Unit / Kalotsa Pad I Well #10
chris wallacetillalaska aov
J✓`
Well
Kalotsa 10
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min.
PTO
2241470
Typa Inj
N -
Tubing
0
3124 -
3070
3060
Time Test
P
Packer TVD
1192
BBLPump
0.7 -
IA
0
12
12
12
Interval
0
Test psi
WOO 1BBLRetuml
0.7
OA
0
0
0
0
Result
P
Notes:
Post completion 3112" tieback string and Inner.
Well
Kalotsa 10
Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min.
PTO
2241470
Type Inj
N -
Tubing
0
BO
80
80
Type Test
P
Packer TVD
1192 -
BBLPump
0.5 -
IA
0
3193
3179 -
3175
Interval
0
Test psi
MOO
BBLRetum
1 0.5
OA
0
0
0
0-
Result
P
Notes:
Post completion 75I8" a 3 In' annulus. Pai at 1192' had
Well
Pressures: Pretest trained 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inj
Tubing
Type Test
Packer TVD
BBLPump
IA
Interval
Test 01
BBLRetum
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min,
PTO
Type Inj
Tubing
Type Test
Packer ND
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inj
Tubing
Typa Test
Packer TVD
BBLPump
IA
Interval
Test psi
BEL Return
OA
Result
Nei
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Typelnj
Tubing
Type Test
Packer TVD
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inj
Tubing
Type Tesl
Packer ND
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Never
Well
Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Tubing
Type Test
Pecker TVD
IA
Interval
Test psi
g8BL
OA
Result
NIP¢:
TYPE INJ C.
TYPE TEST Cures
INTERVAL Cabs
Result codes
W=Water
P=Pressure Ted
1=Initial Test
P=Para
G=Gas
0= finer ldesuiCe la Ni
4=Fwr Year Crain
F=Fad
S=Slurry
V x ReOuired by Vaninae
1=lnwnalusive
I= Industrial Wass lm
O= order(dexntw In noses)
N= "t lnleudl
Form 10 26 (Revised 012017)
MIT Hllaarp 16902-0 25
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: 02/28/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
WELL: KALOTSA 10
PTD: 224-147
API: 50-133-20732-00-00
FINAL LWD FORMATION EVALUATION LOGS (01/19/2025 to 02/04/2025)
ROP, DGR, ADR, PCG-K, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
Please include current contact information if different from above.
224-147
T40160
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.28 15:16:10 -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: 2/16/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250216
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset #
BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf
CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL
CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL
CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL
IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf
KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL
KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL
KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL
KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL
MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF
NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf
PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT
PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT
PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT
PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN
PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT
PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL
PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT
Revision Explanation: Annotations added to processed log.
Please include current contact information if different from above.
162-037 T40080
T40081
T40082
T40082
T40083
T40084
T40085
T40086
T40087
T40088
T40089
T40090
T40091
T40092
T40093
T40094
T40095
T40096
T40097
KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.02.18 13:06:47 -09'00'
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2
2.Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6.API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,950'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; N/A 1,222' MD/1,204' TVD, N/A
7,679'7,948'7,677'
Ninilchik Beluga/Tyonek Gas Pool
16"
7-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
NINU Kalotsa 10CO 701C
Same
7,861'3-1/2"
~2,555psi
6,726'
N/A
Length
February 20, 2025
Tieback 3-1/2"
7,948'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,890psi
120'120'
1,422'
Size
120'
1,422'
MD
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
1,229'
10,160psi
1,394'
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
C061505, ADL 384372
224-147
50-133-20732-00-00
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 written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
66
t
2
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
325-061
By Gavin Gluyas at 11:29 am, Feb 07, 2025
Noel Nocas
(4361)
Digitally signed by Noel
Nocas (4361)
Date: 2025.02.07 09:56:01
-09'00'
DSR-2/14/25BJM 2/17/25
CT BOP test to 3000 psi
Shallowest allowable perf is 4172 TVD. See Chad Helgeson email attached
Perforate
Yes, for CT scope only 2/14/25
Bryan McLellan
10-407
X
Submit CBL and obtain AOGCC approval before perforating.
SFD 2/11/2025*&:
2/18/2025
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.02.18 10:37:48 -09'00'
RBDMS JSB 021825
Well Prognosis
Well Name: Kalotsa 10 API Number: 50-133-20732-00-00
Current Status: New Drill Well Permit to Drill Number: 224-147
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: 3307 psi @ 7517’ TVD (Based on 0.44 psi/ft gradient)
Max. Potential Surface Pressure:2555 psi (Based on 0.1 psi/ft gas gradient to surface)
Applicable Frac Gradient: 1.06 psi/ft using 20.3 ppg EMW FIT at the 7-5/8” surface casing shoe
Shallowest Allowable Perf TVD: MPSP/(1.06-0.1) = 2555 psi / 0.96 = 2661‘ TVD
Top of Applicable Gas Pool: 1474’ MD/1432’ TVD (Beluga-Tyonek)
Well Status: New Drill Initial Completion
Brief Well Summary
Kalotsa 10 is a new drill well targeting the Tyonek and Beluga sands. This objective of this sundry is to clean out
the liner with coil tubing/nitrogen and perforate the Tyonek 3-140.
Wellbore Conditions:
- Max Inclination – 27.8° at 1,445’ MD
- Max DLS °/100’ – 4.5° at 826’ MD
- Liner is full of ~9.1 ppg 6% KCl mud
- Tubing and IA are displaced to 8.4 ppg CIW
- T & IA have been pressure tested to 3000 psi
Pre-Sundry Work:
1. Review all approved COAs
2. MIRU E-line and pressure control equipment
3. Log well with CBL tool in 3-1/2” liner
a. Send results to AOGCC to review prior to perforating
4. RDMO E-line
Procedure:
1. MIRU Coil Tubing and pressure control equipment
2. PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24hr notice for BOP test
3. RIH & clean out wellbore to ~7875’ MD (~8’ above landing collar), displace liner to 8.4 ppg water
4. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore
a. ~69 bbls total wellbore volume
5. RDMO Coil Tubing
6. MIRU E-line and pressure control equipment
7. PT lubricator to 250 psi low / 3,000 psi high
8. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically
targeting 20% underbalance)
9. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up:
It is unlikely that formation strength
is 20.3 ppg from sc shoe to TD.
Use known FIT/LOT data in the area
to plot pore-pressure/frac gradient
curve and determine shallowest
allowable perf. Shallowest perf allowed with
this sundry is 4172' TVD per C. Helgeson
email attached 2/17/25. -bjm
1.06 psi/ft using 20.3 ppg EMW FIT
Well Prognosis
Below are proposed targeted sands in order of testing (bottom/up),
but additional sand may be added depending on results of these
perfs, between the proposed top and bottom perfs
Sand Top
MD Btm MD Top TVD Btm TVD Interval
TY_3 ±4,057' ±4,064' ±3,821' ±3,828' ±7'
TY_3 ±4,066' ±4,077' ±3,830' ±3,841' ±11'
TY_5 ±4,178' ±4,184' ±3,941' ±3,947' ±6'
TY_5 ±4,200' ±4,207' ±3,963' ±3,970' ±7'
TY_5A ±4,256' ±4,262' ±4,019' ±4,025' ±6'
TY_5B ±4,295' ±4,301' ±4,057' ±4,063' ±6'
TY_6 ±4,321' ±4,341' ±4,083' ±4,103' ±20'
TY_6 ±4,366' ±4,376' ±4,128' ±4,138' ±10'
TY_7 ±4,454' ±4,474' ±4,215' ±4,235' ±20'
TY_7 ±4,498' ±4,518' ±4,259' ±4,279' ±20'
TY_8 ±4,528' ±4,542' ±4,288' ±4,302' ±14'
TY_9A ±4,626' ±4,646' ±4,385' ±4,405' ±20'
TY_10B ±4,706' ±4,716' ±4,465' ±4,475' ±10'
TY_10B ±4,720' ±4,730' ±4,479' ±4,489' ±10'
TY_10B ±4,736' ±4,746' ±4,494' ±4,504' ±10'
TY_11A ±4,845' ±4,850' ±4,602' ±4,607' ±5'
TY_12 ±4,924' ±4,930' ±4,681' ±4,687' ±6'
TY_12 ±4,942' ±4,950' ±4,699' ±4,707' ±8'
TY_13 ±5,176' ±5,179' ±4,930' ±4,933' ±3'
TY_14 ±5,252' ±5,255' ±5,006' ±5,009' ±3'
TY_15 ±5,314' ±5,328' ±5,067' ±5,081' ±14'
TY_16 ±5,404' ±5,414' ±5,156' ±5,166' ±10'
TY_17 ±5,438' ±5,474' ±5,190' ±5,226' ±36'
TY_17 ±5,477' ±5,504' ±5,229' ±5,256' ±27'
TY_17 ±5,512' ±5,518' ±5,263' ±5,269' ±6'
TY_17 ±5,524' ±5,532' ±5,275' ±5,283' ±8'
TY_17 ±5,542' ±5,548' ±5,293' ±5,299' ±6'
TY_18 ±5,565' ±5,571' ±5,316' ±5,322' ±6'
TY_18 ±5,609' ±5,636' ±5,359' ±5,386' ±27'
TY_37 ±5,814' ±5,839' ±5,562' ±5,587' ±25'
TY_37 ±5,856' ±5,864' ±5,604' ±5,612' ±8'
TY_37 ±5,869' ±5,875' ±5,616' ±5,622' ±6'
TY_43 ±6,026' ±6,049' ±5,772' ±5,795' ±23'
TY_43 ±6,057' ±6,069' ±5,803' ±5,815' ±12'
TY_53 ±6,540' ±6,567' ±6,281' ±6,308' ±27'
TY_65 ±6,755' ±6,785' ±6,424' ±6,454' ±30'
TY_67 ±6,824' ±6,836' ±6,563' ±6,575' ±12'
Well Prognosis
TY_90 ±7,202' ±7,208' ±6,938' ±6,944' ±6'
TY_90 ±7,213' ±7,223' ±6,949' ±6,959' ±10'
TY_90 ±7,228' ±7,252' ±6,963' ±6,987' ±24'
TY_90 ±7,273' ±7,293' ±7,008' ±7,028' ±20'
TY_90 ±7,309' ±7,316' ±7,044' ±7,051' ±7'
TY_90 ±7,324' ±7,330' ±7,059' ±7,065' ±6'
TY_90 ±7,339' ±7,349' ±7,073' ±7,083' ±10'
TY_118 ±7,582' ±7,640' ±7,314' ±7,372' ±58'
TY_120 ±7,647' ±7,673' ±7,379' ±7,405' ±26'
TY_140 ±7,753' ±7,793' ±7,484' ±7,524' ±40'
TY_140 ±7,796' ±7,830' ±7,517' ±7,551' ±34'
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations
i. Pending well production, all perf intervals may not be completed
ii. Note: Note: A CIBP may be used instead of WRP if it is determined that no cement
is needed for operational purposes.
iii. If necessary, use nitrogen to pressure up well during perforating or to depress
water prior to setting a plug above perforations
10. RDMO
11. Turn well over to production & flow test well
12. Test SVS as necessary once well has reached stable flow rates
a. Notify state 48 hrs prior to testing within 5 days of stable production
Coil Procedure (Contingency)
1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,000 psi high
a. Provide AOGCC 24 hr notice for BOP test
2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth
3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Coil Tubing BOP Schematic
4. Standard Well Procedure – N2 Operations
Updated by SRW 02-06-25
SCHEMATIC
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 7,948’ / TVD = 7,677’
TD = 7,950’ / TVD = 7,679’
RKB to GL = 18.5’
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (75% Lead excess)
3-1/2” Est. TOC @ TOL (40% excess)
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,222’ 7,948’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf ±1,222’
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,222’ 4.875” 6.540” Liner hanger / LTP Assembly
2 ±1,222’ 4.790” 6.340” Seal Stem
6-3/4”
hole
1/2
Updated by SRW 2-6-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PBTD = 7,948’ / TVD = 7,677’
TD = 7,950’ / TVD = 7,679’
RKB to GL = 18.5’
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (75% Lead excess)
3-1/2” Est. TOC @ TOL (40% excess)
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 GBCD 6.875” Surf 1,422’
3-1/2" Prod Lnr 9.2 L-80 Wedge 563 2.992” 1,222’ 7,948’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf ±1,222’
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,222’ 4.875” 6.540” Liner hanger / LTP Assembly
2 ±1,222’ 4.790” 6.340” Seal Stem
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_3 ±4,057' ±4,064' ±3,821' ±3,828' ±7' Proposed TBD
TY_3 ±4,066' ±4,077' ±3,830' ±3,841' ±11' Proposed TBD
TY_5 ±4,178' ±4,184' ±3,941' ±3,947' ±6' Proposed TBD
TY_5 ±4,200' ±4,207' ±3,963' ±3,970' ±7' Proposed TBD
TY_5A ±4,256' ±4,262' ±4,019' ±4,025' ±6' Proposed TBD
TY_5B ±4,295' ±4,301' ±4,057' ±4,063' ±6' Proposed TBD
TY_6 ±4,321' ±4,341' ±4,083' ±4,103' ±20' Proposed TBD
TY_6 ±4,366' ±4,376' ±4,128' ±4,138' ±10' Proposed TBD
TY_7 ±4,454' ±4,474' ±4,215' ±4,235' ±20' Proposed TBD
TY_7 ±4,498' ±4,518' ±4,259' ±4,279' ±20' Proposed TBD
TY_8 ±4,528' ±4,542' ±4,288' ±4,302' ±14' Proposed TBD
TY_9A ±4,626' ±4,646' ±4,385' ±4,405' ±20' Proposed TBD
TY_10B ±4,706' ±4,716' ±4,465' ±4,475' ±10' Proposed TBD
TY_10B ±4,720' ±4,730' ±4,479' ±4,489' ±10' Proposed TBD
TY_10B ±4,736' ±4,746' ±4,494' ±4,504' ±10' Proposed TBD
TY_11A ±4,845' ±4,850' ±4,602' ±4,607' ±5' Proposed TBD
TY_12 ±4,924' ±4,930' ±4,681' ±4,687' ±6' Proposed TBD
TY_12 ±4,942' ±4,950' ±4,699' ±4,707' ±8' Proposed TBD
TY_13 ±5,176' ±5,179' ±4,930' ±4,933' ±3' Proposed TBD
TY_14 ±5,252' ±5,255' ±5,006' ±5,009' ±3' Proposed TBD
TY_15 ±5,314' ±5,328' ±5,067' ±5,081' ±14' Proposed TBD
TY_16 ±5,404' ±5,414' ±5,156' ±5,166' ±10' Proposed TBD
TY_17 ±5,438' ±5,474' ±5,190' ±5,226' ±36' Proposed TBD
TY_17 ±5,477' ±5,504' ±5,229' ±5,256' ±27' Proposed TBD
TY_17 ±5,512' ±5,518' ±5,263' ±5,269' ±6' Proposed TBD
TY_17 ±5,524' ±5,532' ±5,275' ±5,283' ±8' Proposed TBD
TY_17 ±5,542' ±5,548' ±5,293' ±5,299' ±6' Proposed TBD
TY_18 ±5,565' ±5,571' ±5,316' ±5,322' ±6' Proposed TBD
TY_18 ±5,609' ±5,636' ±5,359' ±5,386' ±27' Proposed TBD
TY_37 ±5,814' ±5,839' ±5,562' ±5,587' ±25' Proposed TBD
TY_37 ±5,856' ±5,864' ±5,604' ±5,612' ±8' Proposed TBD
TY_37 ±5,869' ±5,875' ±5,616' ±5,622' ±6' Proposed TBD
TY_43 ±6,026' ±6,049' ±5,772' ±5,795' ±23' Proposed TBD
TY_43 ±6,057' ±6,069' ±5,803' ±5,815' ±12' Proposed TBD
Perforation detail continued on pg 2.
6-3/4”
hole
1/2
Updated by SRW 2-6-25
PROPOSED
Ninilchik Unit
Kalotsa 10
PTD: 224-147
API: 50-133-20732-00-00
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY_53 ±6,540' ±6,567' ±6,281' ±6,308' ±27' Proposed TBD
TY_65 ±6,755' ±6,785' ±6,424' ±6,454' ±30' Proposed TBD
TY_67 ±6,824' ±6,836' ±6,563' ±6,575' ±12' Proposed TBD
TY_90 ±7,202' ±7,208' ±6,938' ±6,944' ±6' Proposed TBD
TY_90 ±7,213' ±7,223' ±6,949' ±6,959' ±10' Proposed TBD
TY_90 ±7,228' ±7,252' ±6,963' ±6,987' ±24' Proposed TBD
TY_90 ±7,273' ±7,293' ±7,008' ±7,028' ±20' Proposed TBD
TY_90 ±7,309' ±7,316' ±7,044' ±7,051' ±7' Proposed TBD
TY_90 ±7,324' ±7,330' ±7,059' ±7,065' ±6' Proposed TBD
TY_90 ±7,339' ±7,349' ±7,073' ±7,083' ±10' Proposed TBD
TY_118 ±7,582' ±7,640' ±7,314' ±7,372' ±58' Proposed TBD
TY_120 ±7,647' ±7,673' ±7,379' ±7,405' ±26' Proposed TBD
TY_140 ±7,753' ±7,793' ±7,484' ±7,524' ±40' Proposed TBD
TY_140 ±7,796' ±7,830' ±7,517' ±7,551' ±34' Proposed TBD
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
1
McLellan, Bryan J (OGC)
From:Chad Helgeson <chelgeson@hilcorp.com>
Sent:Monday, February 17, 2025 3:13 PM
To:McLellan, Bryan J (OGC)
Cc:Donna Ambruz; Scott Warner
Subject:RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Bryan,
Thanks for catching that I used the BHP instead of the MPSP.
So the correct math would be:
Applicable Frac Gradient: 0.7124 psi/ft using 13.73 ppg EMW
Shallowest Allowable Perf TVD: MPSP/(0.7124-0.1) = (3307-752 psi) / 0.6124= 4172‘ TVD
Prior to perforating shallower than 4215ft TVD (Ty_7), Hilcorp will provide data to AOGCC showing the BHP is less
than frac gradient of shallower perfs, or will have zones plugged off that may be at pressures above the frac
gradient of the sand.
Chad Helgeson
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Monday, February 17, 2025 2:43 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>
Subject: RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Chad,
I think there’s an error in your calculation for shallowest allowable perf depth. You used BHP instead of MPSP. It
should be 2556 psi/0.6124 psi/ft = 4174’ TVD.
Let me know if you agree and I’ll update the 10-403.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
2
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Friday, February 14, 2025 3:35 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com>
Subject: RE: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Bryan,
In the Perf sundry for Kalotsa #10 we requested perforating the Tyonek 3 Sand @ 3821 TVD to the Tyonek 140 sand
at 7517’ TVD.
I could not find a frac gradient curve for this field, but will keep looking. It should be noted that this part (structure)
of the Ninilchik field, most gas sands are depleted, which was confirmed with the reservoir pressure data that was
collected in January when we drilled Kalotsa #9. We did not collect pressure data for each sand that is proposed
to be perforated in Kalotsa #10, however it does show there are several sands that have current reservoir
pressures less than 0.1 psi/ft and several are at or below a 0.05 psi/ft. With these low pressure reservoirs Hilcorp
is confident that deeper sands at higher pressure will not frac shallower sands.
To move forward with this request, I pulled all the FIT’s from Kalotsa drill wells, threw out the ones above 15ppg
and get an average FIT of 13.72 ppg. See table below.
Kalotsa well LOT
Well # FIT TVD Date
1 14.3 1380 12/21/2016
2 14.2 1379 2/6/2017
3 14.3 1316 6/12/2017
4 13.5 1410 5/20/2017
5 13.57 1071 9/27/2020
6 12.5 1258 9/24/2019
7 21.78 1389 10/26/2020
8 16.66 1662 2/12/2022
9 18.7 1382 1/6/2025
10 20.37 1386 1/25/2025
Average highlighted tests – 13.73 ppg
For purposes of this project if we use a 13.73 ppg Frac gradient and the deepest proposed perf open with a BHP of
3307 psi, the shallowest available perf will be at the T37 sand or 5400ft.
Applicable Frac Gradient: 0.7124 psi/ft using 13.73 ppg EMW
Shallowest Allowable Perf TVD: MPSP/(0.7124-0.1) = 3307 psi / 0.6124= 5400‘ TVD
Prior to perforating shallower than 5400ft TVD, Hilcorp will provide data to AOGCC showing the BHP is less than
frac gradient of shallower perfs, or will have zones plugged off that may be at pressures above the frac gradient of
the sand.
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.
3
In the reservoir pressures collected on Kalotsa #9 the T90 Sand which is proposed to be the 5 th zone perforated has
a bottom hole pressure in of 332 pisa to 408 psia with 3 different spots checked. The T3 sand has pressures of 247
psia.
Hilcorp will provide additional BHP data prior to perforating shallower than 5400ft TVD .
I will continue to look for a frac gradient plot to see if we can provide that to you to have confidence at other
depths.
Thanks
Chad Helgeson
Operations Engineer
Kenai Team
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Friday, February 14, 2025 1:16 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Subject: [EXTERNAL] Fwd: Kalotsa 10 (PTD 224-147) Perf sundry
Chad, here’s what I sent to Scott
Sent from my iPhone
Begin forwarded message:
From: "McLellan, Bryan J (OGC)" <bryan.mclellan@alaska.gov>
Date: February 12, 2025 at 3:49:00ௗPM AKST
To: Scott Warner <Scott.Warner@hilcorp.com>
Subject: Kalotsa 10 (PTD 224-147) Perf sundry
Scott,
The calculation for shallowest allowable perforation on the sundry application is based on an
extrapolation of the 20.3 ppg LOT pressure at the surface casing shoe at 1422’ TVD. This is an
unusually high frac pressure and although it seems that the formation strength at this casing
setting depth is repeatable over several nearby wells, I don’t think we can assume it extends to all
the sands down to TD.
Can Hilcorp provide a Pore-Pressure/Frac Gradient curve for this region? It could be based on
deeper leakoff tests on other nearby wells and any petrophysical data that you might have to help
get a more realistic picture of frac pressure vs. depth.
Thanks
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
4
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
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the recipient should carry out such virus and other checks as it considers appropriate.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________NINILCHIK UNIT KALOTSA 10
JBR 03/13/2025
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:I showed up a little early so they had a couple of things left to do but got them done and we had a good test.
TEST DATA
Rig Rep:Jon EveraOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley
Contractor/Rig No.:Hilcorp 169 PTD#:2241470 DATE:1/22/2025
Well Class:DEV Inspection No:divRCN250123162419
Inspector Bob Noble
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:NA NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:9.875 P
Vent Line(s) Size:16 P
Vent Line(s) Length:109 P
Closest Ignition Source:115 P
Outlet from Rig Substructure:98 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:NA
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:27 P
Knife Valve Open Time:1 P
Diverter Misc:NA
Systems Pressure:P3000
Pressure After Closure:P1500
200 psi Recharge Time:P27
Full Recharge Time:P118
Nitrogen Bottles (Number of):P4
Avg. Pressure:P2450
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
NA NAMud System Misc:
9
9
9
9
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
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Ninilchik Unit, Beluga/Tyonek Gas Pool, NINU Kalotsa 10
Hilcorp Alaska, LLC
Permit to Drill Number: 224-147
Surface Location: 2075' FSL, 468' FWL, Sec 7, T1S, R13W, SM, AK
Bottomhole Location: 2590' FSL, 1256' FEL, Sec 12, T1S, R14W, SM, AK
Dear Mr. McLaughlin:
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,
Gregory C. Wilson
Commissioner
DATED this 7th day of January 2025.
Gregory C. Wilson
Digitally signed by Gregory C.
Wilson
Date: 2025.01.07 12:56:17 -09'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 8,141' TVD: 7,861'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 144.1 15. Distance to Nearest Well Open
Surface: x-209863 y-2233349 Zone-4 126.1 to Same Pool: 250' to Pax 4
16. Deviated wells:Kickoff depth: 500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 25 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 GBCD 1,429' Surface Surface 1,429' 1,394'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 6,912' 1,229' 1,211' 8,141' 7,861'
Tieback 3-1/2" 9.2# L-80 EUE 1,229' Surface Surface 1,229' 1,211'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Kalotsa 10
Ninilchik Unit
Beluga/Tyonek Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Total Depth MD (ft):Total Depth TVD (ft):
022224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
L - 1618 ft3 / T - 131 ft3
2673
2221' FSL, 224' FWL, Sec 7, T1S, R13W, SM, AK
2590' FSL, 1256' FEL, Sec 12, T1S, R14W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
2075' FSL, 468' FWL, Sec 7, T1S, R13W, SM, AK C061505, ADL 384372
18. Casing Program:Top - Setting Depth - BottomSpecifications
3459
GL / BF Elevation above MSL (ft):
Plugs (measured):
(including stage data)
Driven
L - 414 ft3 / T - 208 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
LengthCasing Size
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
Intermediate
Drilling Manager
Sean Mclaughlin
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
1/15/2025
3512' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
Tieback Assy.
4762
Cement Volume MD
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s Nos No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Grace Christianson at 2:11 pm, Nov 19, 2024
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2024.11.19 13:55:52 -
09'00'
Sean
McLaughlin
(4311)
NINU
50-133-20732-00-00
DSR-11/21/24BJM 1/6/25
224-147
A.Dewhurst 06DEC24
BOP test to 3000 psi, annular test to 2500 psi
Submit FIT/LOT data and obtain approval before drilling production hole.
Minimum 19 ppg FIT/LOT required to drill to planned TD.
&':IRU-/&
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.01.07 12:46:00 -09'00'
01/07/25
01/07/25
RBDMS JSB 010825
KALOTSA 10
PTD Program
Ninilchik Field
November 18, 2024
KALOTSA 10
Drilling Procedure
Contents
1.0 Well Summary................................................................................................................................2
2.0 Management of Change Information...........................................................................................3
3.0 Tubular Program:..........................................................................................................................4
4.0 Drill Pipe Information:..................................................................................................................4
5.0 Internal Reporting Requirements................................................................................................5
6.0 Planned Wellbore Schematic........................................................................................................6
7.0 Drilling / Completion Summary...................................................................................................7
8.0 Mandatory Regulatory Compliance / Notifications....................................................................8
9.0 R/U and Preparatory Work........................................................................................................10
10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11
11.0 Drill 9-7/8” Hole Section..............................................................................................................12
12.0 Run 7-5/8” Surface Casing..........................................................................................................14
13.0 Cement 7-5/8” Surface Casing....................................................................................................16
14.0 BOP N/U and Test........................................................................................................................18
15.0 Drill 6-3/4” Hole Section..............................................................................................................19
16.0 Run 3-1/2” Production Liner......................................................................................................21
17.0 Cement 3-1/2” Production Liner................................................................................................25
18.0 3-1/2” Liner Tieback Polish Run................................................................................................28
19.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................29
20.0 Diverter Schematic ......................................................................................................................30
21.0 BOP Schematic.............................................................................................................................31
22.0 Wellhead Schematic.....................................................................................................................32
23.0 Anticipated Drilling Hazards......................................................................................................33
24.0 Hilcorp Rig 169 Layout...............................................................................................................35
25.0 FIT/LOT Procedure ....................................................................................................................36
26.0 Rig 169 Choke Manifold Schematic...........................................................................................37
27.0 Casing Design Information.........................................................................................................38
28.0 6-3/4” Hole Section MASP..........................................................................................................39
29.0 Spider Plot w/ 660’.......................................................................................................................40
30.0 Surface Plat As-Built...................................................................................................................41
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1.0 Well Summary
Well KALOTSA 10
Pad & Old Well Designation Kalotsa Pad – Grassroots Well
Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore)
Target Reservoir(s)Tyonek / Lower Beluga
Planned Well TD, MD / TVD 8141 MD / 7861’ TVD
PBTD, MD / TVD 8041’ MD
AFE Number
AFE Drilling Days
AFE Drilling Amount
Maximum Anticipated Pressure
(Surface)2673 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3459 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB 144.10’
Ground Elevation 126.10’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
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2.0 Management of Change Information
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3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 -
Surface
9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 GBCD 6890 4790 683
Prod
6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
** Liner must overlap surface casing by at least 100’.
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellView.
x Report covers operations from 6am to 6am
x Ensure time entry adds up to 24 hours total.
x Capture any out-of-scope work as NPT.
5.2 Afternoon Updates
x Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
x Submit a short operations update each morning by 7am in NDE – Drilling Comments
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills:
x Notify Drlg Manager
1. Sean McLaughlin: C: 907-223-6784
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and
cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
KALOTSA 10 is an S-shaped directional grassroots development well to be drilled from Kalotsa Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Tyonek and Lower Beluga sands.
The base plan is an S-shaped directional wellbore with a kickoff point at ~500’ MD. Maximum hole angle
will be ~25 deg. and TD of the well will be 8141’ TMD/ 7861’ TVD, ending with 8 deg inclination.
Drilling operations are expected to commence approximately January, 2025. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 1429’ MD / 1394’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine
TOC. Necessary remedial action will then be discussed with AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste
Cells.The contingency plan will be tohaul cuttingsto theKenai Gas Field G&I facility for disposal / beneficial
reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 169 to wellsite
2. N/U diverter and test.
3. Drill 9-7/8” hole to 1429’ MD. Run and cmt 7-5/8” surface casing.
4. Test casing to 3500 psi. Perform 17.0# FIT
5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi
6. Drill 6-3/4” hole section to 8141’ MD.
7. GeoTap RFT interval identified by Geologist
8. Run and cmt 3-1/2” production liner.
9. Displace well to 6% KCL completion fluid.
10. POOH and LDDP.
11. RIH and land 3-1/2” tieback string in liner top.
12. Test IA to 3000; Test tubing to 3000 psi
13. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo + GEOTAP
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations. If
additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to
contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling of KALOTSA 10. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office.
x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the
conditions of approval are captured in shift handover notes until they are executed and complied
with.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to testing BOPs.
x Any other notifications required in APD.
Additional requirements may be stipulated on APD and Sundry.
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Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
9.0 R/U and Preparatory Work
9.1 Set 16” conductor at +/-120’ below ground level.
9.2 Dig out and set impermeable cellar.
9.3 Install landing ring on conductor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.8 Mix mud for 9-7/8” hole section.
9.9 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” 2M Diverter
10.1 N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE:Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
10.5 Estimated Diverter line orientation on Kalotsa Pad:
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11.0 Drill 9-7/8” Hole Section
11.1 P/U 9-7/8” directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2” Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8” hole section to 1429’ MD/ 1394’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Inlet experience to drill through coal seams efficiently.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x TD the hole section in a good shale
x Take MWD surveys every stand drilled (60’ intervals).
11.5 9-7/8” hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-1429’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Parker 7-5/8” casing running equipment.
x Ensure 7-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 7-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
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12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
13.0 Cement 7-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will
consist of lead & tail, TOC brought to surface.
Estimated Total Cement Volume:
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13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 – 18 hours after CIP.
13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
Verified cement calcs. -bjm
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cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.14 R/D cement equipment. Flush out wellhead with FW.
13.15 Back out and L/D landing joint. Flush out wellhead with FW.
13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.17 Lay down landing joint and pack-off running tool.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test
Packoff to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
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x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Land out test plug (if not installed previously).
x Test BOP to 250/3000 psi for 5/10 min.
x Test VBR’s with 3-1/2” and 4-1/2” test joints
x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint
x Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section.
15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
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Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
1429’- 8141’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0
System Formulation:6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0–10ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
x Triple Combo LWD tools required (DEN, POR, RES)
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8” L-80 burst is 6880 psi / 2 = 3440 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
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15.13 Conduct FIT to 17.2 ppg EMW. A 17.2# ppg FIT with 8.5 ppg BHP and 9.2 ppg MW will result
in a 15 bbl KTV.
15.14 Drill 6-3/4” hole section to 8141’ MD / 7861’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x Trip back to the 7-5/8” shoe about ½ way through the hole section
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Lost BHA on Kalotsa 8. Maintain good hole cleaning and add Black product to the
mud.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed
necessary.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RIH to TD, pump sweep, CBU and condition mud for casing run.
15.19 POOH LDDP and BHA
15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint.
16.0 Run 3-1/2” Production Liner
16.1. R/U Parker 3-1/2” casing running equipment.
x Ensure 3-1/2” HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
Page 22 Rev PTD November 18, 2024
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x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with YJOC landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2” production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint to the 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 3-1/2” production liner
Page 23 Rev PTD November 18, 2024
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Page 24 Rev PTD November 18, 2024
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16.6. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 3-1/2” X 7-5/8” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up
weights.
16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom.
Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the
shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and
thinners.
16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good
condition for cementing.
Page 25 Rev PTD November 18, 2024
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17.0 Cement 3-1/2” Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Page 26 Rev PTD November 18, 2024
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17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP
entering into liner.
17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 0.7 bbls.
Verified cement calcs
Page 27 Rev PTD November 18, 2024
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17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up
pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops
rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to
overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes.
Ensure to report the following on WellView:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
Page 28 Rev PTD November 18, 2024
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x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 3-1/2” Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC
procedure.
18.3. POOH, and LDDP and polish mill.
18.4. If not completed, test 3-1/2” casing to 3000 psi and chart for 30 minutes
Page 29 Rev PTD November 18, 2024
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19.0 3-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked
up per tally.
x No SSSV, CIM, or GLM required.
19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
19.3 Circulate inhibited completion fluid.
19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 3-1/2” liner and tieback to 3000 psi and chart for 30 minutes.24 hr notice required.
19.7 Test 7-5/8” x 3-1/2” annulus to 3000 psi and chart for 30 minutes.24 hr notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO Hilcorp Rig #169
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20.0 Diverter Schematic
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21.0 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Anticipated Drilling Hazards
9-7/8” Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 – 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
Page 34 Rev PTD November 18, 2024
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 35 Rev PTD November 18, 2024
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24.0 Hilcorp Rig 169 Layout
Page 36 Rev PTD November 18, 2024
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Drilling Procedure
PTD xxx-xxx
25.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 37 Rev PTD November 18, 2024
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26.0 Rig 169 Choke Manifold Schematic
Page 38 Rev PTD November 18, 2024
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Drilling Procedure
PTD xxx-xxx
27.0 Casing Design Information
Page 39 Rev PTD November 18, 2024
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28.0 6-3/4” Hole Section MASP
See attached emails for revised table with corrected anticipated pressures. -A.Dewhurst 06DEC24.
Page 40 Rev PTD November 18, 2024
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Drilling Procedure
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29.0 Spider Plot w/ 660’
Page 41 Rev PTD November 18, 2024
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30.0 Surface Plat As-Built
!
" #
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750
Vertical Section at 284.00° (1500 usft/in)
Kalotsa 10 wp02 Tgt1
7 5/8" x 9 7/8"
3 1/2" x 6 3/4"
500
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
40 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 5 0 0
8 0 0 0
8 1 4 1
Kalotsa 10 wp02
Start Dir 3º/100' : 500' MD, 500'TVD
End Dir : 1333.33' MD, 1307.14' TVD
Start Dir 3º/100' : 3333.33' MD, 3119.75'TVD
End Dir : 3900' MD, 3661.09' TVD
Total Depth : 8141' MD, 7860.82' TVD
BEL 10
BEL 53
BEL 82
BEL 134
T 5
T 16
T 65
T 83
T 142
T 146
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Kalotsa 10
126.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2233349.31 209863.74 60° 6' 13.6388 N 151° 35' 24.0558 W
SURVEY PROGRAM
Date: 2024-11-14T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.00 1430.00 Kalotsa 10 wp02 (Kalotsa 10)3_MWD+IFR1+MS+Sag
1430.00 8141.00 Kalotsa 10 wp02 (Kalotsa 10) 3_MWD+IFR1+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
1461.10 1317.00 1503.21 BEL 10
2122.10 1978.00 2232.54 BEL 53
2727.10 2583.00 2900.08 BEL 82
3520.10 3376.00 3756.73 BEL 134
3935.10 3791.00 4176.70 T 5
5095.10 4951.00 5348.10 T 16
6465.10 6321.00 6731.56 T 65
6762.10 6618.00 7031.48 T 83
7585.10 7441.00 7862.57 T 142
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Kalotsa 10, True North
Vertical (TVD) Reference:RKB Permit @ 144.10usft (HEC 169)
Measured Depth Reference: RKB Permit @ 144.10usft (HEC 169)
Calculation Method: Minimum Curvature
Project:Ninilchik Unit
Site:Kalotsa
Well:Kalotsa 10
Wellbore:Kalotsa 10
Design:Kalotsa 10 wp02
CASING DETAILS
TVD TVDSS MD Size Name
1394.00 1249.90 1429.17 7-5/8 7 5/8" x 9 7/8"
7860.82 7716.72 8141.00 3-1/2 3 1/2" x 6 3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00
2 500.00 0.00 0.00 500.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 500' MD, 500'TVD
3 1333.33 25.00 284.00 1307.14 43.29 -173.62 3.00 284.00 178.94 End Dir : 1333.33' MD, 1307.14' TVD
4 3333.33 25.00 284.00 3119.75 247.77 -993.75 0.00 0.00 1024.17 Start Dir 3º/100' : 3333.33' MD, 3119.75'TVD
5 3900.00 8.00 284.00 3661.09 286.56 -1149.34 3.00 180.00 1184.53 End Dir : 3900' MD, 3661.09' TVD
6 8141.00 8.00 284.00 7860.82 429.35 -1722.04 0.00 0.00 1774.76 Total Depth : 8141' MD, 7860.82' TVD
-400-300-200-1000100200300400500600700800South(-)/North(+) (200 usft/in)-1800 -1700 -1600 -1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600 -500 -400 -300 -200 -100 0 100West(-)/East(+) (200 usft/in)Kalotsa 10 wp02 Tgt17 5/8" x 9 7/8"3 1/2" x 6 3/4"25050075010001250150017502000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077507861Kalotsa 10 wp02Start Dir 3º/100' : 500' MD, 500'TVDEnd Dir : 1333.33' MD, 1307.14' TVDStart Dir 3º/100' : 3333.33' MD, 3119.75'TVDEnd Dir : 3900' MD, 3661.09' TVDTotal Depth : 8141' MD, 7860.82' TVDCASING DETAILSTVDTVDSS MDSize Name1394.00 1249.90 1429.17 7-5/8 7 5/8" x 9 7/8"7860.82 7716.72 8141.00 3-1/2 3 1/2" x 6 3/4"Project: Ninilchik UnitSite: KalotsaWell: Kalotsa 10Wellbore: Kalotsa 10Plan: Kalotsa 10 wp02WELL DETAILS: Kalotsa 10126.10+N/-S +E/-W Northing Easting Latitude Longitude0.00 0.00 2233349.31 209863.74 60° 6' 13.6388 N 151° 35' 24.0558 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 10, True NorthVertical (TVD) Reference:RKB Permit @ 144.10usft (HEC 169)Measured Depth Reference:RKB Permit @ 144.10usft (HEC 169)Calculation Method:Minimum Curvature
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0.001.503.004.50Separation Factor0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000Measured DepthNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Kalotsa 10 NAD 1927 (NADCON CONUS)Alaska Zone 04126.10+N/-S+E/-W Northing EastingLatitudeLongitude0.000.002233349.31 209863.74 60° 6' 13.6388 N151° 35' 24.0558 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Kalotsa 10, True NorthVertical (TVD) Reference:RKB Permit @ 144.10usft (HEC 169)Measured Depth Reference:RKB Permit @ 144.10usft (HEC 169)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2024-11-14T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool18.00 1430.00 Kalotsa 10 wp02 (Kalotsa 10) 3_MWD+IFR1+MS+Sag1430.00 8141.00 Kalotsa 10 wp02 (Kalotsa 10) 3_MWD+IFR1+MS+Sag0.0040.0080.00120.00160.00200.00Centre to Centre Separation0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000Measured DepthKalotsa 1Kalotsa 2Kalotsa 3Kalotsa 4Kalotsa 5Kalotsa 6Kalotsa 7Kalotsa 8Kalotsa 9 wp02GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.00 To 8141.00Project: Ninilchik UnitSite: KalotsaWell: Kalotsa 10Wellbore: Kalotsa 10Plan: Kalotsa 10 wp02Ninilchik UnitLadder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name1394.00 1249.90 1429.17 7-5/8 7 5/8" x 9 7/8"7860.82 7716.72 8141.00 3-1/2 3 1/2" x 6 3/4"
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.
NINU Kalotsa-10
224-147
BELUGA-TYONEK GAS
NINILCHIK
1
Dewhurst, Andrew D (OGC)
From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent:Friday, 6 December, 2024 13:04
To:Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL] NINU Kalotsa-10 PTD (224-147): Question
Follow Up Flag:Follow up
Flag Status:Flagged
Andy,
Updated Kalotsa 10 table below.
sean
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Friday, December 6, 2024 11:09 AM
To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl,
Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] NINU Kalotsa-10 PTD (224-147): Question
Sean,
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
2
Thanks for providing the updated table for the Kalotsa-9. As you said, I see the same issue in this one also. Would you
please send a corrected version? I realize it will be almost iden Ɵcal.
Thanks,
Andy
Andrew Dewhurst
Senior Petroleum Geologist
Alaska Oil and Gas ConservaƟon Commission
333 W. 7th Ave, Anchorage, AK 99501
andrew.dewhurst@alaska.gov
Direct: (907) 793-1254
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WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:NINILCHIK UNIT KALOTSA 10Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241470NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes C061505 and ADL3843722 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA-TYONEK GAS - 562503 - governed by CO 701C4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)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 horizonsYes Kick Tolerance is very low, unless LOT is >19 ppg. May need to truncate TD based on LOT value.23 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 = 2673 psi. BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not anticipated based on nearby wells35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating max pore pressure of 9.23 ppg EMW.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/6/2024ApprBJMDate12/24/2024ApprADDDate12/6/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate
