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1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
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 7,703 feet See Schematic feet
true vertical 7,325 feet 6460' (fill) feet
Effective Depth measured 5,639 feet 3,122 feet
true vertical 5,371 feet 2,980 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth) Tieback 4-1/2" 12.6# / L-80 3,122' MD 2,979' TVD
Packers and SSSV (type, measured and true vertical depth) LTP; N/A 3,122' MD 2,980' 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: Ryan LeMay, Operations Engineer
Contact Email:ryan.lemay@hilcorp.com
Authorized Title: Contact Phone:
661-487-0871
7,500psi
2,980psi
6,870psi
8,430psi
3,318' 3,165'
Burst Collapse
1,410psi
4,750psi
Production
Liner
4,611'
Casing
Structural
7,321'7,701'
120'Conductor
Surface
Intermediate
16"
9-5/8"
120'
3,318'
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-091
50-133-20714-00-00
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:
FEDA028406/FEDA028384
Swanson River / Beluga Gas
Swanson River Unit (SRU) 232-15
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
120'
0 02400
0 3520
1428
325-343
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 11:24 am, Jul 21, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.07.18 17:36:52 -
08'00'
Noel Nocas
(4361)
BJM 9/25/25
Page 1/1
Well Name: SRF SRU 232-15
Report Printed: 7/16/2025WellViewAdmin@hilcorp.com
Alaska Weekly Report - Operations
Wellbore API/UWI:50-133-20714-00-00 Field Name:Swanson River State/Province:ALASKA
Permit to Drill (PTD) #:223-091 Sundry #:325-343 Rig Name/No:
Jobs
Actual Start Date:6/20/2025 End Date:
Report Number
1
Report Start Date
6/19/2025
Report End Date
6/19/2025
Last 24hr Summary
MIRU slickline. PT lubricator 250 / 2500 psi - good. Make initial tag @ 4,001'KB- tag higher w/3" DD Bailer @ 3918'KB-Run G-Ring to clear up tubing walls-Tag @
3893'KB. Bailing throughout the day and leave off @ 3891'KB. RDMO slickline
Report Number
2
Report Start Date
6/23/2025
Report End Date
6/24/2025
Last 24hr Summary
Mobilize Fox CTU 10 to location. Complete PTW / PJSM. Spot coil unit and support equipment. MIRU coil unit and support equipment. Completed BOPE test 250
psi low / 2500 psi high as per sundry. AOGCC Jim Regg waived witness. Secure well. SDFN.
Report Number
3
Report Start Date
6/24/2025
Report End Date
6/25/2025
Last 24hr Summary
Complete PTW/PJSM. P/U injector. M/U CTC and FCO BHA - 2.70 JSN. Shell test 250 psi low / 2500 psi high. RIH w/BHA. POOH to troubleshoot Fox system
hydraulics. Coil mechanic called out to fix CTU system hydraulics.
Report Number
4
Report Start Date
6/25/2025
Report End Date
6/26/2025
Last 24hr Summary
Complete PTW/PJSM. P/U injector. M/U CTC and FCO BHA - 2.70 JSN. Shell test 250 psi low/2500 psi high. RIH w/BHA, load well w/FW. Dry tagged @ 3,983'
CTM. PUH & establish 1:1 returns. Cleanout from 3983'-5542'.Broke through bridge @ 5542', lost returns & WHP. Shut in choke. Perform fluff & stuff to 5700'. Pooh
w/BHA. M/U drift BHA - 3.70" JSN. RIH to 5700' no issues. Push fluid away w/ pad gas. WHP broke over @ 1,750 psi. POOH w/BHA. MIRU YJ Eline. P/T 250 low /
2,500 high. RIH, POOH, issues with depth control panel not reading.
Report Number
5
Report Start Date
6/26/2025
Report End Date
6/27/2025
Last 24hr Summary
Complete PTW/PJSM. MIRU YJ Eline. P/U lubricator and test 250 psi low / 2500 psi high. RIH w/ 3.5" CIBP. Correlate & set CIBP @ 5,639'. PU and come back
down to confirm good plug set. POOH. Pressure up to 1,400 psi w/ pad gas. RIH w/ 6' x 2 3/4" 6 SPF 60deg gun, Perforate. LB 51-2 (5,617-5,623) POOH. Bull
plug dry, production to flow test well.
Report Number
6
Report Start Date
6/27/2025
Report End Date
6/28/2025
Last 24hr Summary
Crew travel to location, complete PTW/PJSM. P/U lubricator, pressure test 250 psi low/ 2500 psi high. Presure up with pad gas to 1650 psi. RIH w/ 8' x 2 3/4" 6
SPF 60deg gun, Perforate. LB 51-1(5,575-5,583) POOH. Confirm all shots fired. RDMO YJ Eline and turn well over to production.
Complete PTW/PJSM. MIRU YJ Eline. P/U lubricator and test 250 psi low / 2500 psi high. RIH w/ 3.5" CIBP. Correlate & set CIBP @ 5,639'. PU and come back Complete PTW/PJSM. MIRU YJ Eline. P/U lubricator and test 250 psi low / 2500 psi high. RIH w/ 3.5" CIBP. Correlate & set CIBP @ 5,639'. PU and come back
down to confirm good plug set. POOH. Pressure up to 1,400 psi w/ pad gas. RIH w/ 6' x 2 3/4" 6 SPF 60deg gun, Perforate. LB 51-2 (5,617-5,623) POOH. Bull
Complete PTW/PJSM. MIRU YJ Eline. P/U lubricator and test 250 psi low / 2500 psi high. RIH w/ 3.5" CIBP. Correlate & set CIBP @ 5,639'. PU and come back
Crew travel to location, complete PTW/PJSM. P/U lubricator, pressure test 250 psi low/ 2500 psi high. Presure up with pad gas t
SPF 60deg gun, Perforate. LB 51-1(5,575-5,583) POOH. Confirm all shots fired. RDMO YJ Eline and turn well over to production.
Updated by 07-16-25
SCHEMATIC
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618 MD / TVD = 7,244
TD = 7,703 MD / TVD = 7,325
RKB to GL = 18.0
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102.
Notes:
RA Tags @ 5588 & 6602
Short joints (20ft) @ 6105 & 7121
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16Conductor Driven
to Set Depth 84 X-56 Weld 15.01 Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681Surf 3,318
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.9583,0897,701
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958Surface 3,122
1
16
9-5/8
12-1/4
hole
4-1/2
JEWELRY DETAIL
No. Depth ID OD Item
1 3,122 3.958 6.370
Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
2 5,639CIBP (6/26/25)
3 5,869CIBP (4/23/24)
4 6,390CIBP w/ 35 cement TOC @ 6,355' (4/22/24)
5 6,852CIBP (set 3/29/24)
6 6,943Cement Retainer (coil set 3/28/24)
8-1/2
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
LB 51-1 5,5755,5835,3105,31786/27/25 Open
LB 51-2 5,6175,6235,3505,35566/26/25 Open
LB 51-2 5,649'5,658'5,380'5,389'9'4/23/2024 Isolated
LB 52-9 5,889'5,897'5,608'5,616'8'4/22/2024 Isolated
TY 61-8 6,7546,7746,1086,129203/29/2024 Isolated
TY 62-3 6,8676,8876,2186,237203/28/2024 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/2023 Isolated
TY 8-0 7,551' 7,570' 7,180' 7,199' 19' 12/6/2023 Isolated
RA 6602
RA 5588
6
5
Fill @
6460
tagged
4/3/24
4
3
2
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,703'6,460' (fill)
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
ryan.lemay@hilcorp.com
661-487-0871
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
Ryan LeMay, 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
FEDA028406/FEDA028384
223-091
50-133-20714-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
3,122'
8,430psi
3,165'
Size
120'
3,318'
MD
See Attached Schematic
2,980psi
6,870psi
120'120'
3,318'
June 18, 2025
Tieback 4-1/2"
7,701'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 232-15CO 716A
Same
7,321'4-1/2"
~1865psi
4,611'
See Schematic
Length
LTP; N/A 3,122 MD/ 2,980' TVD; N/A, N/A
7,325'5,869'5,589'
Swanson River Beluga Gas
16"
9-5/8"
See Attached Schematic
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
By Grace Christianson at 10:04 am, Jun 05, 2025
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2025.06.04 19:32:30 -
08'00'
Noel Nocas
(4361)
325-343
A.Dewhurst 10JUN25
10-404
CT BOP test to 2500 psi.
BJM 6/11/25 DSR-6/17/25
X
*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.06.18 10:42:38 -08'00'06/18/25
RBDMS JSB 062325
Well Prognosis
Well: SRU 232-15
Well Name: SRU 232-15 API Number: 50-133-20714-00-00
Current Status: Gas Producer Permit to Drill Number: 223-091
Regulatory Contact: Donna Ambruz (907) 777-8305
First Call Engineer: Ryan LeMay (661)487-0871 (M)
Second Call Engineer: Scott Warner (907) 830-8863 (M) (907) 564-4506 (O)
Maximum Expected BHP: 2414 psi @ 5485’ TVD Based on 0.44 psi/ft
Max. Potential Surface Pressure: 1865 psi Based on 0.1 psi/ft gas gradient to surface
Applicable Frac Gradient: 0.63 psi/ft using 12.1 ppg EMW FIT at the 9-5/8” casing shoe
Shallowest Allowable Perf TVD: MPSP/(0.63-0.1) = 1865 psi / 0.53 = 3519‘ TVD
Top of Applicable Gas Pool / PA: 5249’ MD / 4998’ TVD (Beluga)
Well Status: Gas Producer
x 678 mcfd / 11 bwpd / 139 psi FTP as of June 3, 2025
Recent Well Summary:
SRU 232-15 was drilled with Hilcorp Rig 169 in November 2023 targeting Beluga and Tyonek sands in the north
block of Swanson River Field. The most recent well work was completed in April of 2024, LB 52-9 perforations
were isolated, and LB 51-2 perforations were added. Initial production from the LB 51-2 zone came on between
3.5-4 mmcfd. Gas production has declined over the past year and the well is currently producing 678 mcfd / 11
bwpd / 139 psi FTP as of June 3, 2025.
The objective of this Sundry is to add additional perforations in the Beluga sands.
Procedure:
1. MIRU E-line and pressure control equipment
2. PT lubricator to 250 psi low / 2,500 psi high
3. RIH and perforate the following sands from bottom up:
Below are proposed targeted sands in order of testing (bottom/up),
but additional sand may be added depending on results of these
perfs, between the proposed top and bottom perfs
Well Name Zone Top Md Bottom Md Top TVD Bottom TVD Total
SRU 232-15 MB 49-5 5,253’ 5,269’ 5,002’ 5,017’ 16’
SRU 232-15 MB 49-5 5,287’ 5,294’ 5,034’ 5,041’ 7’
SRU 232-15 LB 50-7 5,347’ 5,353’ 5,092’ 5,098’ 6’
SRU 232-15 LB 50-7 5,390’ 5,398’ 5,133’ 5,141’ 8’
SRU 232-15 LB 50-7 5,403’ 5,409’ 5,145’ 5,151’ 6’
SRU 232-15 LB 50-9 5,500’ 5,509’ 5,239’ 5,246’ 9’
SRU 232-15 LB 50-9 5,528’ 5,534’ 5,265’ 5,270’ 6’
SRU 232-15 LB 51-1 5,549’ 5,554’ 5,284’ 5,289’ 5’
SRU 232-15 LB 51-1 5,575’ 5,583’ 5,310’ 5,317’ 8’
SRU 232-15 LB 51-2 5,617’ 5,623’ 5,350’ 5,355’ 6’
Well Prognosis
Well: SRU 232-15
SRU 232-15 LB 51-2 5,663’ 5,672’ 5,393’ 5,402’ 9’
SRU 232-15 LB 51-3 5,703’ 5,717’ 5,431’ 5,445’ 14’
SRU 232-15 LB 51-4 5,747’ 5,759’ 5,473’ 5,485’ 12’
a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to
the Operations Engineer, Reservoir Engineer, and Geologist for confirmation
b. Use Gamma/CCL to correlate
c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min
intervals post perf shot (if using switched guns, wait 10 min between shots)
d. Pending well production, all perf intervals may not be completed
e. If any current or proposed zone produces sand and/or water or needs isolated, RIH and set
plug above the perforations OR patch across the perforations
i. Note: A CIBP may be used instead of WRP if it is determined that no cement is
needed for operational purposes. 35ft will not be placed on each plug as these
zones are close together. If possible, the CIBP will be set 50’ above of the top of
the last perforated sand unless zones are too close together in which case the plug
will be set within 50’.
f. If necessary, use nitrogen or high-pressure pad gas to pressure up well during perforating or to
depress water prior to setting a plug above perforations
4. RDMO
Contingency Procedure: Coiled Tubing Cleanout
1. If throughout the job any current or proposed zones produce sand and / or water that cannot be
depressed and pushed away with nitrogen or high-pressure pad gas, a coil tubing unit may be rigged up
to clean out fill or fluid blown down as necessary.
a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high
i. Provide AOGCC 24hrs notice of BOP test.
b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary.
Attachments:
1. Current Schematic
2. Proposed Schematic
3. Coil Tubing BOP Diagram
4. Standard Well Procedure – N2 Operations
Updated by DMA 04-29-24
SCHEMATIC
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
2 5,869’CIBP (4/23/24)
3 6,390’CIBP w/ 35’ cement – TOC @ 6,355' (4/22/24)
4 6,852’CIBP (set 3/29/24)
5 6,943’Cement Retainer (coil set 3/28/24)
8-1/2”
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
LB 51-2 5,649'5,658'5,380'5,389'9'4/23/2024 Open
LB 52-9 5,889'5,897'5,608'5,616'8'4/22/2024 Isolated
TY 61-8 6,754’6,774’6,108’6,129’20’3/29/2024 Isolated
TY 62-3 6,867’6,887’6,218’6,237’20’3/28/2024 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/2023 Isolated
TY 8-0 7,551'7,570'7,180'7,199'19'12/6/2023 Isolated
RA 6602’
RA 5588’
5
4
Fill @
6460’
tagged
4/3/24
3
2
Updated by RPL 06-4-25
SCHEMATIC
Proposed
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
2 5,869’CIBP (4/23/24)
3 6,390’CIBP w/ 35’ cement – TOC @ 6,355' (4/22/24)
4 6,852’CIBP (set 3/29/24)
5 6,943’Cement Retainer (coil set 3/28/24)
8-1/2”
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
MB 49-5 5,253’5,269’5,002’5,017’16’Proposed Proposed
MB 49-5 5,287’5,294’5,034’5,041’7’Proposed Proposed
LB 50-7 5,347’5,353’5,092’5,098’6’Proposed Proposed
LB 50-7 5,390’5,398’5,133’5,141’8’Proposed Proposed
LB 50-7 5,403’5,409’5,145’5,151’6’Proposed Proposed
LB 50-9 5,500’5,509’5,239’5,246’9’Proposed Proposed
LB 50-9 5,528’5,534’5,265’5,270’6’Proposed Proposed
LB 51-1 5,549’5,554’5,284’5,289’5’Proposed Proposed
LB 51-1 5,575’5,583’5,310’5,317’8’Proposed Proposed
LB 51-2 5,617’5,623’5,350’5,355’6’Proposed Proposed
LB 51-2 5,649'5,658'5,380'5,389'9'4/23/2024 Open
LB 51-2 5,663’5,672’5,393’5,402’9’Proposed Proposed
LB 51-3 5,703’5,717’5,431’5,445’14’Proposed Proposed
LB 51-4 5,747’5,759’5,473’5,485’12’Proposed Proposed
LB 52-9 5,889'5,897'5,608'5,616'8'4/22/2024 Isolated
TY 61-8 6,754’6,774’6,108’6,129’20’3/29/2024 Isolated
TY 62-3 6,867’6,887’6,218’6,237’20’3/28/2024 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/2023 Isolated
TY 8-0 7,551'7,570'7,180'7,199'19'12/6/2023 Isolated
RA 6602’
RA 5588’
5
4
Fill @
6460’
tagged
4/3/24
3
2
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2
Development Exploratory
3. Address:Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number):8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 7,703 feet See Schematic feet
true vertical 7,325 feet 6460' (fill) feet
Effective Depth measured 5,869 feet 3,122 feet
true vertical 5,589 feet 2,980 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)Tieback 4-1/2" 12.6# / L-80 3,122' MD 2,979' TVD
Packers and SSSV (type, measured and true vertical depth)LTP; N/A 3,122' MD 2,980' 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:
7,500psi
2,980psi
6,870psi
8,430psi
3,318'3,165'
Burst Collapse
1,410psi
4,750psi
Production
Liner
4,611'
Casing
Structural
7,321'7,701'
120'Conductor
Surface
Intermediate
16"
9-5/8"
120'
3,318'
measured
TVD
4-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-091
50-133-20714-00-00
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:
FEDA028406/FEDA028384
Swanson River / Tyonek Gas
Swanson River Unit (SRU) 232-15
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
0
Gas-Mcf
MD
0
Size
120'
0 03927
0 11640
1726
Jake Flora, Operations Engineer
324-095 & 324-203
Sr Pet Eng:Sr Pet Geo:Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Noel Nocas, Operations Manager 907-564-5278
N/A
jake.flora@hilcorp.com
907-777-8442
p
k
ft
t
Fra
O
s
6. A
G
L
PG
,
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
By Grace Christianson at 12:59 pm, May 01, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.05.01 11:43:04 -
08'00'
Noel Nocas
(4361)
DSR-5/1/24
RBDMS JSB 051324
Well Name: SRF SRU 232-15
API #:50-133-20714-00-00 Field:Swanson River Start Date:3/24/2024
Permit #:223-091 Sundry #:324-095 & 324-203 End Date:4/23/2024
3/24/2024
3/25/2024
3/26/2024
3/27/2024
4/3/2024
4/22/2024
4/23/2024
Activity Report
PJSM, Crew travel to location, Pick up injector head & lube, Check all inline screens & pump string wiper ball, Pick up & make up Yellow
jacket one-run plug, run in hole & set @ 6943' on coil measurement, Pull out of hole circulating, Lay down tools & running tool, Make up
reverse nozzle & run in hole to unload hole, Calculated: 119 bbls, Actual: 121, Pull out of hole, Trap 2000 psi on well, Rig down coil.
PJSM, Crew travel to location, Pick up injector head & Make up coil connector, Pull & pressure test-good, Make up BHA w/ 3.75" tricone
bit, Make up lube & run in hole, Tag @ 6790', Clean out from 6790' to 7105', Circulate while reciprocating pipe, Pull out of hole & lay
down BHA, Spot in & rig up AK Eline, Pick up & make up 3.51" plug & lube, Pressure test 250/3000-good, Run in hole, Tag @ 6825' (work
multiple times), Pull out of hole & pick up 2.77" GR, Run in hole & tag @ 6825', Work from 6825' to 6975', Pull out of hole, Pick up 3.5"
CIBP & run in hole to tag @ 6797', Pull out of hole & lay down tools, Secure well & rig down for the night
PJSM, Crew travel to location, Pick up injector & make up 2-1/8" Wash nozzle, Load reel & pressure test stripper-3000 psi, Run in hole
while pumping, Tag @ 6618', Clean out from 6618' to 7020', Tag hard @ 7020' Unable to pass 7020', Pull out of hole & rig down coil, Rig
up Eline over coil, pick up 3.51" CIBP & lube. Pressure test lube 250/3000-good, Run in hole & tag @ 6844', Attempt to work past (no
movement), Pull out of well & rig down eline, Secure well.
PJSM, Crew travel to location, Spot in & rig up equipment, Pressure test BOPE 250 low/ 3000 high-good (no retests), Secure well.
Rig up slickline p/t lub. To 2500psi good test
RIH w/ 3.5'' g-ring to 6442'slm 6460'kb fell slow from 6000' real thick fluid pooh possible fluid level
OOH rig down slickline clean tools - area secure well for prod.
Fuel & park equip. turn in permit head to shop
YJEL PTW & PJSM. MIRU, PT 250 psi / 2550 psi. SITP - 2550 psi. RIH with CIBP and set at 6390'. Dump bail 35' (22 gal.) cement on plug (Est.
TOC - 6355'). Draw down well pressure 1700 psi. Perforate LB 52-9 (5889'-5897'), pressure build 1698 psi - 1738 psi in 45 min. M/U and
RIH with GPT, locate FL at 6075' (280' above TOC). Draw well down to 1600 psi - FL at 5975', draw down to 1500 psi - FL at 5825'(~64'
above perfs). Secure well and SDFN. M/U gas jumper line and apply 2600 psi to wellbore overnight.
Daily Operations:
PJSM, Crew travel to location, Spot in & rig up, Pick up Gun #1 & lube to test @ 250/3000 psi-good, Run #1 TY62-3 (6967-6987), Pull out of
hole & pick up GPT, Run in hole, Fluid level @ 6196', Tag @ 6913' Pull up hole & push away fluid, Pressure up to 4500 psi & leave over
night to push fluid.
PJSM, Crew travel to location, Start & warm equipment, Pick up CCL/GPT & lube, Pressure test 250/3000-good, Run in hole with CCL/GPT,
Fluid @ 6170', Tag @ 6287', Pull out of hole (clay packed around tools), Push away with pad gas & rig down Eline, Mob to next well.
YJ E-line PTW & PJSM. SITP - 2125 psi. M/U GPT and CIBP. Locate fluid level at 5900', below perfs at 5889'-5897'. Set CIBP at 5869'. Bleed
down tubing to 1700 psi. Perforate the LB_51-2 interval 5649'-5658'.
WHP Start:1717 psi, after 15 min: 2036 psi. Flowed well at 1.0 mmcfd at 1995 psi. SI well, M/U second gun and reperf LB_51-2. SITP - 2050
psi. Final pressure post perf: 2050 psi. Begin flow test at previous choke setting. 30 min: 1.0mmcfd/2000 psi. Next hour: (open choke
100m): 1.3mmcfd/1980 psi. Next hour (open choke 200 m) Last reading: 1.6 mmcfd /1958 psi
Page 1 of 1
Updated by DMA 04-29-24
SCHEMATIC
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
2 5,869’CIBP (4/23/24)
3 6,390’CIBP w/ 35’ cement – TOC @ 6,355' (4/22/24)
4 6,852’CIBP (set 3/29/24)
5 6,943’Cement Retainer (coil set 3/28/24)
8-1/2”
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
LB 51-2 5,649'5,658'5,380'5,389'9'4/23/2024 Open
LB 52-9 5,889'5,897'5,608'5,616'8'4/22/2024 Isolated
TY 61-8 6,754’6,774’6,108’6,129’20’3/29/2024 Isolated
TY 62-3 6,867’6,887’6,218’6,237’20’3/28/2024 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/2023 Isolated
TY 8-0 7,551'7,570'7,180'7,199'19'12/6/2023 Isolated
RA 6602’
RA 5588’
5
4
Fill @
6460’
tagged
4/3/24
3
2
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/1/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240501
Well API #PTD #Log Date Log Company Log Type AOGCC Eset#
HV B-13 50231200320000 207151 4/10/2024 YELLOW JACKET GPT-PERF
KU 13-06A 50133207160000 223112 3/27/2024 YELLOW JACKET GPT-PERF
KU 13-06A 50133207160000 223112 4/1/2024 YELLOW JACKET GPT-PLUG-PERF
KU 13-06A 50133207160000 223112 3/22/2024 YELLOW JACKET GPT-PERF
KU 33-08 50133207180000 224008 4/30/2024 YELLOW JACKET SCBL
KU 41-08 50133207170000 224005 4/23/2024 YELLOW JACKET SCBL
KU 41-08 50133207170000 224005 4/11/2024 AK E-LINE GPT/Perf/CIBP
MPU F-30A 50029226230100 213188 4/12/2024 READ CaliperSurvey
MPU S-13 50029230930000 202114 4/16/2024 READ Caliper Survey
NCI A-17 50883201880000 223031 3/22/2024 AK E-LINE Perf
Paxton 6 50133207070000 222054 4/14/2024 AK E-LINE GPT/Perf
PBU PTM P1-13 50029223720000 193074 4/8/2024 YELLOW JACKET CBL
SRU 232-15 50133207140000 223091 3/28/2024 YELLOW JACKET GPT-PLUG-PERF
SRU 232-15 50133207140000 223091 4/22/2024 YELLOW JACKET PLUG-PERF
SRU 241-33B 50133206960000 221053 4/12/2024 YELLOW JACKET GPT-PERF
SRU 241-33B 50133206960000 221053 4/4/2024 YELLOW JACKET GPT-PERF
Please include current contact information if different from above.
T38745
T38746
T38746
T38746
T38747
T38748
T38748
T38749
T38750
T38751
T38752
T38753
T38754
T38754
T38755
T38755
SRU 232-15 50133207140000 223091 3/28/2024 YELLOW JACKET GPT-PLUG-PERF
SRU 232-15 50133207140000 223091 4/22/2024 YELLOW JACKET PLUG-PERF
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.05.13 09:32:35 -08'00'
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Joshua Stephenson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Jacob Flora
Subject:SRU 232-15 BOPE Test
Date:Monday, March 25, 2024 2:50:26 PM
Attachments:SR 232-15 BOPE test 3-24-24.xlsx
Good afternoon, please see the attached test sheet for SRU 232-15, If any issues please let me know.
Thank you!
Joshua Stephenson
505-386-8853
Joshua.stephenson@hilcorp.com
Well Site Supervisor
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.
6ZDQVRQ5LYHU8QLW
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmit to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:8 DATE: 3/24/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230910 Sundry #324-095
Operation: Drilling: Workover: X Explor.:
Test: Initial: X Weekly: Bi-Weekly: Other:
Rams:250/3000 Annular:N/A Valves:250/3000 MASP:2441
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 0NA
Permit On Location P Hazard Sec.P Lower Kelly 0NA
Standing Order Posted P Misc.NA Ball Type 0NA
Test Fluid Water Inside BOP 0NA
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 1 1.75" stripper P Trip Tank NA NA
Annular Preventer 0NAPit Level Indicators NA NA
#1 Rams 1 1.75" Pipe/Slip P Flow Indicator NA NA
#2 Rams 1 Blindshear P Meth Gas Detector NA NA
#3 Rams 0NAH2S Gas Detector NA NA
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 2 2-1/16"P Time/Pressure Test Result
HCR Valves 0NASystem Pressure (psi)3100 P
Kill Line Valves 2 2-1/16"P Pressure After Closure (psi)2500 P
Check Valve 0NA200 psi Attained (sec)3 P
BOP Misc 0NAFull Pressure Attained (sec)9 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 1400/4 P
No. Valves 5P ACC Misc 0NA
Manual Chokes 2P
Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 0 NA
#1 Rams 20 P
Coiled Tubing Only:#2 Rams 17 P
Inside Reel valves 1P #3 Rams 0 NA
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:2.0 HCR Choke 0 NA
Repair or replacement of equipment will be made within days. HCR Kill 0 NA
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 3/24/24 @ 12:00
Waived By
Test Start Date/Time:3/24/2024 12:00
(date) (time)Witness
Test Finish Date/Time:3/24/2024 14:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Jim Regg
Fox
Terrenace Rias
Hilcorp Alaska LLC
Joshua Stephenson
SRU 232-15
Test Pressure (psi):
trais@foxak.com
Joshua.stephenson@hilcorp.com
Form 10-424 (Revised 08/2022)2024-0324_BOP_Fox8_SRU_232-15
9
9
9
9
9
9 9
9 9
9
9
MEU
-5HJJ
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
You don't often get email from anthony.knowles@hilcorp.com. Learn why this is important
From:Brooks, Phoebe L (OGC)
To:Anthony Knowles
Cc:Regg, James B (OGC)
Subject:RE: [EXTERNAL] RE: SRU 232-15 BOP test Form
Date:Thursday, January 11, 2024 3:59:04 PM
Attachments:Fox 8 12-01-23 Revised.xlsx
Thanks Anthony. Attached is a revised report changing the rig name to Fox 8, MASP to 2986 per
sundry #323-644, adding the operation type Workover, and changed the BOP Misc. fields to 0 “NA”.
Please review and update your copy or let me know if you disagree.
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the
Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it
to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Anthony Knowles <Anthony.Knowles@hilcorp.com>
Sent: Tuesday, January 9, 2024 7:50 AM
To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Subject: RE: [EXTERNAL] RE: SRU 232-15 BOP test Form
Morning Phoebe,
Sorry for the oversight. I’ve corrected the sheet and inputted the value for Pressure after closure.
Let me know if this is sufficient.
Thanks
Anthony
From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Sent: Monday, January 8, 2024 2:35 PM
To: Anthony Knowles <Anthony.Knowles@hilcorp.com>
Subject: [EXTERNAL] RE: SRU 232-15 BOP test Form
The Pressure After Closure time was left blank; please advise.
Thank you,
Phoebe
6ZDQVRQ5LYHU8QLW
37'
revised 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
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Some people who received this message don't often get email from anthony.knowles@hilcorp.com. Learn why this
is important
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the
Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or
disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it
to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Anthony Knowles <Anthony.Knowles@hilcorp.com>
Sent: Sunday, December 3, 2023 12:55 AM
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>
Subject: SRU 232-15 BOP test Form
Anthony Knowles
Well Site Supervisor
Prudhoe Bay | Alaska
Hilcorp Alaska, LLC
Office: (907) 659-5580
Cellular: (907) 227-2297
Harmony: 2382
anthony.knowles@hilcorp.com
alternate: Dan Scarpellla
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
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:8 DATE: 12/1/23
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2230910 Sundry #323-644
Operation: Drilling: Workover: x Explor.:
Test: Initial: X Weekly: Bi-Weekly: Other:
Rams:250/3500 Annular:n/a Valves:250/3500 MASP:2986
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 0NA
Permit On Location P Hazard Sec.P Lower Kelly 0NA
Standing Order Posted P Misc.NA Ball Type 0NA
Test Fluid Water Inside BOP 0NA
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank NA P
Annular Preventer 0NAPit Level Indicators NA P
#1 Rams 1 Blind/Shears P Flow Indicator NA P
#2 Rams 1 1-3/4" Pipe/Slip P Meth Gas Detector NA P
#3 Rams 0NAH2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 2 2"P Time/Pressure Test Result
HCR Valves 0NASystem Pressure (psi)3000 P
Kill Line Valves 2 2"P Pressure After Closure (psi)2350 P
Check Valve 0NA200 psi Attained (sec)3 P
BOP Misc 0NAFull Pressure Attained (sec)18 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4/1000 psi P
No. Valves 5P ACC Misc 0NA
Manual Chokes 2P
Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 0 NA
#1 Rams 24 P
Coiled Tubing Only:#2 Rams 22 P
Inside Reel valves 1P #3 Rams 0 NA
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:2.0 HCR Choke 0 NA
Repair or replacement of equipment will be made within days. HCR Kill 0 NA
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1/30/2023 12:09AM
Waived By
Test Start Date/Time:12/1/2023 13:00
(date) (time)Witness
Test Finish Date/Time:12/1/2023 15:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Jim Regg
Fox
Test w/ freash water. Bottles precharge - 1350 psi.
Recieved waive of witness from Jim Regg via email on 11/30 15:24
Jeremy Hart
Hilcorp Alaska LLC.
Anthony Knowles
SRU 232-15
Test Pressure (psi):
jeremyhart76@gmail.com
anthony.knowles@hilcorp.com
Form 10-424 (Revised 08/2022)2023-1201_BOP_Fox8_SRU_232-15
MEU
9
9
9
9 9 9
9
9
9999
Fox 8
MASP:2986
Sundry #323-644
Workover:x
BOP Misc 0 NA
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Rance Pederson - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT Test Report Rig 169
Date:Monday, November 27, 2023 11:30:31 AM
Attachments:MIT Hilcorp 169 11-27-23.xlsx
SRU 232-15 MIT Chart_11-27-23.pdf
Please see the attached MIT results for SRU 232-15
Rance Pederson
Drilling Foreman
Swanson River Unit
907-283-1369
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
Swanson River Unit 232-15
PTD 2230910
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230910 Type Inj N Tubing 0 3600 3595 3590 Type Test P
Packer TVD 2991 BBL Pump 1.4 IA 0 155 155 155 Interval O
Test psi 3500 BBL Return 1.4 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230910 Type Inj N Tubing 0 300 300 300 Type Test P
Packer TVD 2991 BBL Pump 2.3 IA 0 3600 3600 3600 Interval O
Test psi 3500 BBL Return 2.3 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska, LLC
Swanson River Field / Swanson River Unit / 12-15 Pad
Waived
Rance Pederson
11/27/23
Notes:MIT-T Post Completion, 9 5/8" liner top packer element at 3103' md/2991' tvd, 4 1/2" tubing and liner.
Notes:
Notes:
Notes:
SRU 232-15
SRU 232-15
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:MIT-IA Post Completion, 9 5/8" liner top packer element at 3103' md/2991' tvd, 9 5/8" x 4 1/2" IA.
Notes:
Notes:
Form 10-426 (Revised 01/2017)2023-1127_MITP_SRU_232-15
J.Regg; 5/6/2024
Test Chart Attached
PTD 2230910
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,703'6,460' (fill)
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, 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
FEDA028406/FEDA028384
223-091
50-133-20714-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
3,122'
8,430psi
3,165'
Size
120'
3,318'
MD
See Attached Schematic
2,980psi
6,870psi
120'120'
3,318'
April 18, 2024
Tieback 4-1/2"
7,701'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 232-15CO 716A
Same
7,321'4-1/2"
~2070psi
4,611'
6,852; 6,954
Length
LTP; N/A 3,122 MD/ 2,980' TVD; N/A, N/A
7,325'6,852'6,203'
Swanson River Tyonek Gas
16"
9-5/8"
See Attached Schematic
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
By Grace Christianson at 8:14 am, Apr 09, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.04.08 17:00:02 -
08'00'
Noel Nocas
(4361)
SFD 4/9/2024
Beluga Gas -bjm
10-404
X
BJM 4/11/24
CT BOP test to 2500 psi, if CT is used.
DSR-4/12/24JLC 4/12/2024
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.04.12 15:36:31
-08'00'04/12/24
RBDMS JSB 041624
Well: SRU 232-15
Well Name: SRU 232-15 API Number: 50-133-20714-00-00
Current Status: Gas Producer Permit to Drill Number: 223-091
First Call Engineer: Jake Flora (720) 988-5375 (c)
Second Call Engineer: Chad Helgeson (907) 229-4824 (c)
Maximum Expected BHP: 2,679 psi @ 6,090’ TVD 0.44 psi/ft gradient
Max. Potential Surface Pressure: 2,070 psi Using 0.1 psi/ft
Current Status: SI Gas Well
Brief Well Summary
SRU 232-15 was drilled with Hilcorp Rig 169 in November 2023 targeting Beluga and Tyonek sands in the north
block of Swanson River Field. The well was brought online in the Tyonek 62, 64, and 68 sands. On 2/4/24 the
well went offline and significant sand was discovered during slickline diagnostic work. A CTU FCO was performed
in March plugging back the Tyonek 62-5 sand, followed by unsuccessful testes in the Tyonek 61-8 & 62-3 sands.
The objective of this sundry is to plug back the Tyonek sands/pool and perforate the Middle & Lower Beluga
sands of the Beluga Gas Pool.
Notes Regarding Wellbore Condition
Top Tyonek Pool: 5923’ MD (5641’ TVD)
Open Perforations: 6754-6777’ MD (6090-6110’ TVD) (Tyonek 61-8)
Recent History
3/29/24 Set CIBP at 6852’, perforate 6754-6777’
3/30/24 GPT fluid level at 6170’, tag fill at 6287’, stack out pad gas to depress
4/03/24 3.5” GR to 6460’ KB, fell slow from 6000’
Procedure
1. RU E-line, PT lubricator to 2500 psi
2. Set CIBP w 35’ cement over the top of fill at ~6400’.
3. Perforate Lower Beluga sands from the bottom up within the below intervals:
Well Name Zone
Top
Md Bottom Md
Top
TVD Bottom TVD Total
Top Beluga Pool 5063 4821
SRU 232-15 MB 49-5 5253 5269 5002 5017 16
SRU 232-15 MB 49-5 5287 5294 5034 5041 7
SRU 232-15 LB 50-7 5347 5353 5092 5098 6
SRU 232-15 LB 50-7 5390 5398 5133 5141 8
SRU 232-15 LB 50-7 5403 5409 5145 5151 6
SRU 232-15 LB 50-9 5501 5508 5239 5246 7
SRU 232-15 LB 51-1 5549 5554 5284 5289 5
SRU 232-15 LB 51-1 5575 5583 5310 5317 8
Well: SRU 232-15
SRU 232-15 LB 51-2 5617 5623 5350 5355 6
SRU 232-15 LB 51-2 5648 5657 5379 5388 9
SRU 232-15 LB 51-2 5663 5672 5393 5402 9
SRU 232-15 LB 52-9 5889 5897 5608 5616 8
Top Tyonek Pool 5923 5641
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations
OR patch across the perforations.
Contingency Coil Tubing Fill Cleanout (if fill is encountered during testing)
1. Provide 24hrs notice of BOP test
2. MIRU coil tubing unit
3. BOP test to 2500 psi
4. Perform fill cleanout
5. Set CIBP over open perfs if isolation is needed
6. Jet well dry with nitrogen
7. Proceed with perforation program
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Nitrogen SOP
4. Coil Tubing BOP Diagram
Updated by JMF 04-04-24
SCHEMATIC
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
2 6,852’CIBP (set 3/29/24)
3 6,943’Cement Retainer (coil set 3/28/24)
8-1/2”
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
TY 61-8 6,754’6,774’6,108’6,129’20’3/29/24 Open
TY 62-3 6,867’6,887’6,218’6,237’20’3/28/24 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/23 Isolated
TY 8-0 7,551'7,570'7,180'7,199'19'12/6/23 Isolated
RA 6602’
RA 5588’
3
2
Fill @
6460’
tagged
4/3/24
Updated by DMA 04-04-24
PROPOSED
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
1A ±6,400’CIBP w/ 35’ cement – TOC @ ~6,365'
2 6,852’CIBP (set 3/29/24)
3 6,943’Cement Retainer (coil set 3/28/24)
8-1/2”
hole
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD FT Date Status
MB 49-5 ±5,253'±5,269'±5,002'±5,017'±16'Proposed TBD
MB 49-5 ±5,287'±5,294'±5,034'±5,041'±7'Proposed TBD
LB 50-7 ±5,347'±5,353'±5,092'±5,098'±6'Proposed TBD
LB 50-7 ±5,390'±5,398'±5,133'±5,141'±8'Proposed TBD
LB 50-7 ±5,403'±5,409'±5,145'±5,151'±6'Proposed TBD
LB 50-9 ±5,501'±5,508'±5,239'±5,246'±7'Proposed TBD
LB 51-1 ±5,549'±5,554'±5,284'±5,289'±5'Proposed TBD
LB 51-1 ±5,575'±5,583'±5,310'±5,317'±8'Proposed TBD
LB 51-2 ±5,617'±5,623'±5,350'±5,355'±6'Proposed TBD
LB 51-2 ±5,648'±5,657'±5,379'±5,388'±9'Proposed TBD
LB 51-2 ±5,663'±5,672'±5,393'±5,402'±9'Proposed TBD
LB 52-9 ±5,889'±5,897'±5,608'±5,616'±8'Proposed TBD
TY 61-8 6,754’6,774’6,108’6,129’20’3/29/2024 Isolated
TY 62-3 6,867’6,887’6,218’6,237’20’3/28/2024 Isolated
TY 62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Isolated
TY 64-5 7,233'7,251'6,876'6,894'18'12/7/2023 Isolated
TY 8-0 7,551'7,570'7,180'7,199'19'12/6/2023 Isolated
RA 6602’
RA 5588’
3
2
Fill @
6460’
tagged
4/3/24
1A
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Donna Ambruz
Subject:RE: SRU 232-15 AOGCC 10-403 324-095 PTD 223-091 - Request for Coil Cleanout
Date:Monday, March 4, 2024 5:52:00 PM
Attachments:image004.png
image005.png
Jake,
Hilcorp has approval to perform the work described in your email below as part of sundry 324-095.
BOP test pressure is 3000 psi.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Monday, March 4, 2024 4:01 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: SRU 232-15 AOGCC 10-403 324-095 PTD 223-091 - Request for Coil Cleanout
Hello Bryan,
In preparation for executing the approved perf add on this well we tagged/bailed and found
the fill had increased to 6638’. It’s now above several of the proposed perf adds.
Hilcorp requests permission to perform the following:
1.Provide 24hrs notice of BOP test
2.MIRU coil tubing unit
3.BOP test to 3000 psi
4.Perform fill cleanout to ~ 7500’
5.Set plug at 6967’ (10’ over the current open perfs)
6.Jet well dry with nitrogen
7.Proceed with perforation program per approved sundry 324-095
Please let me know if you need anything additional in your review.
Thanks,
Jake
From: Donna Ambruz <dambruz@hilcorp.com>
Sent: Wednesday, February 28, 2024 8:49 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Cc: Chad Helgeson <chelgeson@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com>; Scott
Warner <Scott.Warner@hilcorp.com>
Subject: SRU 232-15 AOGCC 10-403 324-095 PTD 223-091 Approved 02-27-24
FYI – Please distribute as necessary.
Thank you.
Donna Ambruz
Operations/Regulatory Tech
KEN Asset Team
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
907.777.8305 - Direct
dambruz@hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 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):
7,703'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; N/A 3,122 MD/ 2,980' TVD; N/A, N/A
7,325'7,618'7,244'
Swanson River Tyonek Gas
16"
9-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 232-15CO 716A
Same
7,321'4-1/2"
~2,441psi
4,611'
N/A
Length
February 27, 2024
Tieback 4-1/2"
7,701'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,870psi
120'120'
3,318'
Size
120'
3,318'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
3,122'
8,430psi
3,165'
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
FEDA028406/FEDA028384
223-091
50-133-20714-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Jake Flora, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
jake.flora@hilcorp.com
907-777-8442
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
m
n
P
s
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
By Grace Christianson at 11:39 am, Feb 20, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.02.16 09:27:27 -
09'00'
Noel Nocas
(4361)
324-095
BJM 2/27/24 SFD 2/20/2024
10-404
DSR-2/21/24
Perforate
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.02.27 16:31:18 -09'00'02/27/24
RBDMS JSB 022824
Well: SRU 232-15
Well Name: SRU 232-15 API Number: 50-133-20714-00-00
Current Status: Gas Producer Permit to Drill Number: 223-091
First Call Engineer: Jake Flora (720) 988-5375 (c)
Second Call Engineer: Chad Helgeson (907) 229-4824 (c)
Maximum Expected BHP: 3,159 psi @ 7,180’ TVD 0.44 psi/ft gradient
Max. Potential Surface Pressure: 2,441 psi Using 0.1 psi/ft
Current Status: SI Gas Well
Brief Well Summary
SRU 232-15 was drilled with Hilcorp Rig 169 in November 2023 targeting Beluga and Tyonek sands in the north
block of Swanson River Field. The well was TD’d, casing cemented and liner run this past weekend. The well was
brought online in the Tyonek 62, 64, and 68 sands. On 2/4/24 the well went offline and significant sand was
discovered during slickline diagnostic work. The objective of this sundry is to increase productivity with additional
Tyonek perforations in the 61 to 62 sands.
Notes Regarding Wellbore Condition
Current gross perf interval 6977-7570’ MD 6633-7199’ TVD
Recent History
2/7/24 3” DDB, bail mud to 6991’
2/8/24 bail mud 6954-6970’
Procedure
1. RU E-line, PT lubricator to 2700 psi
2. Perforate Tyonek sands from the bottom up within the below intervals:
ZONE MD TOP MD BOTTOM TVD TOP TVD BOTTOM
Top Tyonek Gas Pool 5912 5630
TY 61-0 6576 6588 5922 5933
TY 61-0 6636 6646 6313 6323
TY 61-8 6754 6777 6090 6110
TY 62-3 6867 6909 6196 6235
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations
OR patch across the perforations.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Nitrogen SOP
-bjm
Updated by CJD 1-3-24
Current Schematic
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 3,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
8-1/2”
hole
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
TY_62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Open
TY_64-5 7,233'7,251'6,876'6,894'18'12/7/23 Open
TY_68-0 7,551'7,570'7,180'7,199'19'12/6/23 Open
RA 6602’
RA 5588’
Updated by JMF 2-13-24
PROPOSED
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
Notes:
RA Tags @ 5588’& 6602
Short joints (20ft)@ 6105’& 7121’
OPEN HOLE / CEMENT DETAIL
9-5/8" TOC @ Surface (Pumped 259 bbls (565 sx)of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor –Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 3,122’ 3.958” 6.370” Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
8-1/2”
hole
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
TY 61-0 6,576 6,588 5,922 5933 proposed
TY 61-0 6,636 6,646 6,313 6323 proposed
TY 61-8 6,754 6,777 6,090 6110 proposed
TY 62-3 6,867 6,909 6,196 6235 proposed
TY_62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Open
TY_64-5 7,233'7,251'6,876'6,894'18'12/7/23 Open
TY_68-0 7,551'7,570'7,180'7,199'19'12/6/23 Open
RA 6602’
RA 5588’
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
David Douglas Hilcorp Alaska, LLC 3 -0
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503 1j�
Tele: (907) 777-8337
Hilrnrp .Alapka, UX E-mail: david.douglas@hilcorp.com
Date: 01/25/2024
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100 ����
Anchorage, AK 99501 RECEIVED
DATA TRANSMITTAL JAN 2 5 2024
SRU 232-15 A®GC
- PTD 223-091
- API 50-133-20714-00-00
Washed and Dried Well Samples (11/22/2023)
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
SRU 232-15
BOX 1 OF 3
3270' - 4890' MD
SRU 232-15
BOX 2 OF 3
4890' - 6600' MD
SRU 232-15
BOX 3 OF 3
6600' - 7703' MD
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422
Received y: Date:
i�iu ��n0 dL�2 �✓�S Zi231 Z�{
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240112
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
END 1-27 50029216930000 187009 11/16/2023 YELLOWJACKET PERF
KALOTSA 4 50133206650000 217063 9/28/2023 YELLOWJACKET PERF
KALOTSA 8 50133207050000 222003 11/29/2023 YELLOWJACKET PERF
KBU 13-8 50133203040000 177029 11/5/2023 YELLOWJACKET PERF
KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT
KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF
KBU 11-08Z 50133206290000 214044 8/24/2023 AK E-LINE GPT/CIBP/PERF
KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL
KBU 23-05 50133206300000 214061 10/10/2023 AK E-LINE PLT
KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/PERF
MPU I-01 50029220650000 190090 11/18/2023 YELLOWJACKET PERF
PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF
PAXTON 7 50133206430000 214130 9/18/2023 YELLOWJACKET CBL
PAXTON 7 50133206430000 214130 10/7/2023 YELLOWJACKET PERF
SRU 224-10 50133101380100 222124 12/27/2023 YELLOWJACKET GPT-PLUG-PERF
SRU 224-10 50133101380100 222124 11/4/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT
SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT
SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF
SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL
Please include current contact information if different from above.
T38273
T38275
T38277
T38278
T38279
T38280
T38280
T38281
T38282
T38283
T38284
T38285
T38286
T38287
T38288
T38288
T38289
T38289
T38289
T38290
T38290
1/18/2024
T38287
SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF
SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.01.18
11:52:00 -09'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Swanson River Unit
GL: 316.8' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" X-56 120'
9-5/8" L-80 3,164'
4-1/2" L-80 7,323'
4-1/2" L-80 2,979'
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
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):
3,089' 7,701'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy.Tieback
TUBING RECORD
L - 718 sx / T - 180 sx8-1/2"
12-1/4"
Driven
Surface L - 565 sx / T - 255 sx
12.6#
Surface
Surface
3,318'
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
348718 2479984
50-133-20714-00-00November 11, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
12/6/2023 223-091 / 323-644
N/A
SRU 232-15November 22, 20232279' FNL, 868' FWL, Sec 15, T8N, R9W, SM, AK
334.8'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2480338
SETTING DEPTH TVD
2480322
TOP HOLE SIZE
CBL 12-2-23, LWD (DGR, PWD, ALD, EWR-M5, DDSR, DDS2, CTN), Mudlog, Perf/Tie In Logs
Tyonek Gas Pool
AKA028406 / AKA028384
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
350601
350816
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
Conductor
N/A
N/A
N/A
7,703' MD / 7,325' TVD
7,618' MD / 7,244' TVD
1905' FNL, 2530' FEL, Sec 15, T8N, R9W, SM, AK
1919' FNL, 2315' FEL, Sec 15, T8N, R9W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
3,122'
2,948'
Surface
84#
47#
120'
Water-Bbl:
PRODUCTION TEST
12/6/2023
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
00697 0
12/26/2023 24
Flow Tubing
0
1446
N/A14460
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 8:45 am, Jan 04, 2024
Completed
12/6/2023
JSB
RBDMS JSB 010424
GDSR-1/29/24
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Ty 62-5 6,977' 6,633'
1555' 1520'
3111' 2968'
4015' 3824'
4323' 4117'
5312' 5057'
5939' 5655'
6926' 6585'
7174' 6820'
7536' 7165'
7536' 7165'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Tyonek 68-0
Mid Beluga 39
Sterling A1
Lower Beluga 50-6
Tyonek 64-5
Sterling B
Upper Beluga 36
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
INSTRUCTIONS
Tyonek 68-0
Tyonek 53-0
Tyonek 62-5
Wellbore Schematic, Drilling and Completion reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
01/03/24
Monty M
Myers
Updated by CJD 1-3-24
Current Schematic
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,244’
TD = 7,703’ MD / TVD = 7,325’
RKB to GL = 18.0’
Notes:
RA Tags @ 5588’& 6602
Short joints (20ft) @ 6105’ & 7121’
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @ 250 bbls –
rotated and recovered flow) pumped 37 bbls (180 sx) of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns.CBL 12/2/23 -TOC @
3102’.
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,089’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surface 3,122’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
13,122’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
8-1/2”
hole
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
TY_62-5 6,977'7,013'6,633'6,669'36'12/7-8/23 Open
TY_64-5 7,233'7,251'6,876'6,894'18'12/7/23 Open
TY_68-0 7,551'7,570'7,180'7,199'19'12/6/23 Open
RA 6602’
RA 5588’
Page 1/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:11/3/2023 End Date:11/28/2023
Report Number
1
Report Start Date
11/3/2023
Report End Date
11/4/2023
Operation
Crews arrive on location start up gens and begin working on de winterizing equipment, aggitators, Dress mud pumps w/ 5.5'' swabs and liners, eclectrician trouble
shooting surginging and load sharing on gens, mechanic working on quill reinstall for top drive, Travel office trailers to swanson and set into position, offload misc
equipment f/ rig, Clark digging hole and setting cellar, load out gen 3 and boiler for swanson, send windwall basket BOP and gas buster.
Rest crews for night
Report Number
2
Report Start Date
11/4/2023
Report End Date
11/5/2023
Operation
UNplug electrical in pits, pumps and sub structure, finish cutting out beams on sub for replacement, remove lights and handrails, fold up walkways on pits, lower pit
rooves, Load out catwalk and mud pumps, auxiliary fuel tank, load 3 loads of rig mats and pipe racks, Diverter components and BOP Stack, get power to company mans
shack, level pad and prep for felt and liner, work on organizing warehouse and prepping mud pump c can, prep to move components to swanson river
Rest crews for the night
Report Number
3
Report Start Date
11/5/2023
Report End Date
11/6/2023
Operation
Continue Hauling misc. equipment out to staging pad, lay out rig foot print lay felt liner and rig mats, continue working on or ganizing connexes and prepping to move rig,
Rested rig crew for the night.
Report Number
4
Report Start Date
11/6/2023
Report End Date
11/7/2023
Operation
load and haul rig compomnents from nikiski yard to swanson river staging pad, offload doghouse water tank and generator at staging pad, off load mats and misc
equipment, finish welding projects on sub and pit rooves, Load out Sub and carrier, load pits and ship to swanson, load mechanics shop and remaining mats pony subs
and ship to swanson river, clean up CCI Yard of felt and liner and misc debris, Clean and organize connexes at warehouse, clean and paint centrifigal gaurds.
Rest crews for the night
Report Number
5
Report Start Date
11/7/2023
Report End Date
11/8/2023
Operation
Crews on location @ 0600hrs, fire up light plants and loaders, rig movers on location spot in cranes and bring in sub, set sub over well and center, set draw works on sub,
set derrick on sub and pin, spot in pit module #1 set jig spot in pump module and remaining pit modules, set doghouse water tank and gen skid, set in HPU, spot in boiler
house and gen #3, Hook up electrical and hydraluics to rig
Continue hooking up hydrulic lines and electrical, hook up mud lines, Raise derrick and raise pit rooves, begin installing pit windwalls, Hook up power to pit lights, spot in
catwalk and raise beaver slide, continue working on hooking up modules, spot in tool pushers trailer and change shacks, get pow er and coms to pushers shack
Hook up water lines, steam lines, air lines. Spot and power up break shacks and fill with water. Hooker up equalizer lines in p its. Fill rig water tank.
Cont. hooking up steam, water and air lines.
Report Number
6
Report Start Date
11/8/2023
Report End Date
11/9/2023
Operation
Continue Rigging up, finish putting wind walls on pits crane in centrifuge and clam shell, spool up drilling line, continue rig ging up modules, welder arrived install cellar
grating and supports
FInish welding cellar grating in place, pin lower torque tube to upper and prep to scope derrick, take on water to boiler and s tart staging up temp and pressure, fill water
tank, hook up steam lines around rig, continue hauling in equipment and setting up location
Scope derrick and install t-bar. Prep derrick board. Change out behinger clamps in derick. R/U to pick up topdrive. R/U gas buster. Stage up #1 boiler. Install low speed
desender on derrick board.
Install tarps on rig floor, sub structor , and pits. Connect roughneck controller and function test same. Finish staging up boiler and circulate steam through out rig. Connect
stand pipe lines. Remove snow throughout rig and location.
Report Number
7
Report Start Date
11/9/2023
Report End Date
11/10/2023
Operation
Rig up top drive and torque bushing, connect kelly hose and service loop, service top drive, function test roughneck and robiti cs, inspect gear box and swivel, plow and
shovel snow around rig and location, Install bales and elevators, change filters on Mud Pump #1, replace plug on iron roughneck
Rig up rig tongs, install double ball valve and saver sub, install clamps and torque, off load mud and stage on docs, Install wash pipe, install handy berm around rig,
continue rigging up mud tanks suck out water and debris from stacking
Hook up pason for 3rd party shacks. Cont. working on rig acceptance check list, function test mix pumps. Remove snow from containment. Nipple up speed head, spacer
spool and annular.
Torqure bolts on th diverter T and bag. Connect acculator lines to unit. Dress out derrick board. N/U knife valve. Plumb in fittings for annular and knife valve. Connect
accumulator lines. N/U diverter line.
Report Number
8
Report Start Date
11/10/2023
Report End Date
11/11/2023
Operation
Continue N/U diverter vent line, finish connecting pason system, service and repair gun lines and gate valves in pits, dress ou t shakers wrap surface lines with heat
blankets, install mouse hole, fill water with pits start building spud mud, prep rig floor and catwalk to start picking up pipe strap, continue clearing snow from around rig
and walkways
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169Permit to Drill (PTD) #:223-091
Page 2/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
Get RKB's Pressure test surface lines, hook up Gai-Tronics, hang tarps on derrick raising cylinders, Build spud mud, test function test gas alarm system, Work on
accumulator bypassing issue sticky solinoid, function knife valve and annular, get cross overs to floor, strap and tally DP
Adjust and center torque ove hole center. Check/compare all torques. Strap, P/U and rack back 48 jnts of 4.5" DP.
P/U and rack back 54 jnts of 4.5" DP. P/U and rack back 16 jnts of 4.5" HWDP. M/U Jar stand. Function test diverter bag.
Report Number
9
Report Start Date
11/11/2023
Report End Date
11/12/2023
Operation
P/U and Rack Back 24 jts of DP, remove mousehole from rotarty install bell nipple and flow line, secure stack
Test diverter with state witness Josh Hunt, test Gas alarms and PVT System, No failures
PJSM P/U BHA as per DD MWD, Upload MWD and Shallow test tools, all checked out
Drill Ahead 12.25'' Surface hole f/ 138' t/560' 460GPM=1219PSI, 43RPM=6.7k tq, 10k WOB,MW=9.0PPG ECD=9.61,P/U=40k S/O=40k ROT=40k, Max gas 0 units
Drill Ahead 12.25'' Surface hole f/ 560' t/963' 525GPM=1509PSI, 43RPM=5.2k tq, 11k WOB,MW=9.3PPG ECD=9.67,P/U=48k S/O=48k ROT=48k, Max gas 4 units
Drill Ahead 12.25'' Surface hole f/ 963' t/1398' 525GPM=1670PSI, 55RPM=4.2k tq, 11k WOB,MW=9.35PPG ECD=9.65,P/U=53k S/O=53k ROT=52k, Max gas 37 units
Report Number
10
Report Start Date
11/12/2023
Report End Date
11/13/2023
Operation
Drill Ahead 12.25'' Surface hole f/ 1398' t/1520' 525GPM=1670PSI, 55RPM=5.5k tq, 12k WOB,MW=9.35PPG ECD=9.45,P/U=56k S/O=54k ROT=55k, Max gas 37 units
Circulate bottoms up, flow check well static, Blow down surface lines
Make wiper trip f/ 1520' t/ 584' with no issues
Service rig and top drive, inspect crown and blocks, grease dra works and inspect brakes
RIH f/ 584' t/ 1520' wash last stand to bottom, Pump High Vis Sweep around back on time 200 % increase in cuttings
Drill Ahead 12.25'' Surface hole f/ 1520' t/1875' 531GPM=1819 PSI, 55RPM= 6.7k tq, 10k WOB,MW=9.4 PPG ECD=9.65, P/U=65k S/O=56k ROT=62k, Max gas 33 units
Troubleshoot mud pump #2 temp/coolant level sensor issue, circulate and reciprocate on one pump.
Drill Ahead 12.25'' Surface hole f/1875' t/2326' 531GPM=1843 PSI, 55RPM= 5.5k tq, 10k WOB,MW=9.1 PPG ECD=9.65, P/U=74k S/O=60k ROT=67k, Max gas 119
units.
Drill Ahead 12.25'' Surface hole f/ 2326' t/2822' 530GPM=1817 PSI, 55RPM= 4.6k tq, 11k WOB,MW=9.25 PPG ECD=9.55, P/U=81k S/O=66k ROT=69k, Max gas 138
units.
Report Number
11
Report Start Date
11/13/2023
Report End Date
11/14/2023
Operation
Drill Ahead 12.25'' Surface hole f/ 2822' t/3335' 530GPM=2000 PSI, 55RPM= 4.6k tq, 9k WOB,MW=9.2 PPG ECD=9.25, P/U 92k S/O=75k ROT=83k, Max gas 247 units.
Circulate bottoms up 540 gpm 2149 psi, Flow check well static
POOH on elevators f/ 3335' t/ 1525' with no issues, Hole fill Calc 13.3 bbls Act 17.7 bbls
Service rig and Top Drive, Inspect Draw works and break linkage
RIH f/ 1525' t/ 3335' No issues
Pump hi-vis sweep and circulate hole clean. Sweep back on time with10% increase in cuttings.
POOH on elevators f/3335' t/151'. Pulled tight at 397', couldnt work through back ream to 338'. Hole fill CALC-22.9 bbls ACT-29 .7
L/D BHA #1. L/D flex collars. Download MWD data. L/D rest of BHA. Bit Graded: 2-3-BT-PT-X-I-PN-TD. Clean and clear rig floor.
Level rig and Dummy run hanger
PJSM - R/U Parker casing equipment for 9-5/8" casing run.
M/U 9-5/8” shoe track and Baker loc all connections. RIH with 9-5/8" 47# L-80 BTC casing t/197’.
Report Number
12
Report Start Date
11/14/2023
Report End Date
11/15/2023
Operation
Cont PU single in hole with 9 5/8" 47# L-80 TXP-BTC surface casing, torqued to 24K ft/lbs, from 197' to 683'. At 683' set down numerous times and could not get
through. LD single jnt.
MU circ swedge with 5' pup, MU topdrive, broke circ at 300 gpm and began working pipe. Worked from 683' up to 647' seeing as much as 30K overpull there. Finally
broke through at 683', cont to work until that 36' stretch was good and clean. Shut down pump, removed circ swedge/pup, blew down topdrive.
Up wt 52K, dwn wt 30K.
Cont PU single in hole from 683' to 1620', filling on the fly, topping off every 10 jnts.
MU circ swedge and topdrive, CBU at 194 gpm-129 psi. Removed circ swedge and blew down topdrive.
Cont PU single in hole slowly, from 1620' to 3318' with no issue other than little pipe displacement. Up wt 57K, dwn wt 32K. Ca lculated displacement = 46.9 bbls, actual
displacement = 3.9 bbls for entire trip.
Removed elevators, installed buddy bails (bail extensions), installed circ swedge in top of landing joint, PU and MU same on stump, MU topdrive. Broke circ and washed
landing jnt down at 136 gpm-451 psi, landed hanger with no issue.
Staged pump rate up to 250 gpm (6 bpm) 222 psi, up wt 140K, dwn wt 85K, RD casing tongs and remove from rig floor, staged plug launcher on floor, condition mud for
cementing. Staged cementers trucks.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 3/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
MU plug launcher and hardline, Halliburton loaded lines with 5 bbls water and checked for leaks. Halliburton pressure tested li nes at 1100 psi low 4100 psi high, good
tests. Halliburton pumped 60bbls 10.5 ppg Tuned Spacer at 4 bpm-175 psi, dropped bottom plug and pumped 259bbls (565 sx) 12 ppg Type I II lead cement at 5bpm -
244psi to 100psi, followed by 52 bbls (255 sx) 15.8 ppg Type I II tail cement at 4 bpm - 120psi to 130 psi. Halliburton dropped top plug then displaced with 9.4 ppg Spud
Mud at 4 bpm 100psi to 500psi. At 120 bbl into displacement hanger packed off, opened 4” valves and took returns to the cellar. Slowed pump to 2 bpm with 100 bbl to
go. Did bump the plug 240.7 bbls into displacement (calculated 237.4 bbls). Held 1580 psi (FCP of 850 psi) for 3 minutes, bled off and floats held. Bled back 1.5 bbl to
truck. Had 60 bbls of Spacer returns to surface and 60.7 bbls lead cement to surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix water temp 70 deg.
Pumped 50% excess on lead and 50% on tail. Lost 20 bbls throughout the job. Did reciprocate casing. Up wt 140K, dwn wt 100K upon landing hanger 50 bbl into
displacement. CIP at 03:15 hrs, 11/15/2023. RD and released Halliburton.
Clean out cellar. L/D landing joint. P/U johnny whacker and flush stack.
Report Number
13
Report Start Date
11/15/2023
Report End Date
11/16/2023
Operation
RD diverter vent line, knife valve, flowline and flow riser, annular, “T”, spacer spool and adaptor flange. Staged all at cella r entrance.
Verified orientation of wellhead with Production and installed wellhead. Wellhead Rep tested neck seals at 5000 psi for 15 minutes, good test and ran in driver lock screws
to secure wellhead to conductor.
Cont pit cleaning, greasing diverter equipment flanges for storage, brought in CCI crane and staged at cellar. Folded over beaver slide and removed diverter equipment,
staged BOP stack and transferred same to cellar bridge cranes. Assisted Production with pump install on location, CCI cleared trees as they came down on roadway.
Set 16”x11" spacer spool, stabbed BOP stack, installed HCR valves choke and kill lines, installed drip pan and flow riser, opened up ram doors and install rams. Simop
Build two batches of 6% KCL mud. Change to 5" liners in MP #2.
Finish hammering up BOP door bolts. Energize accumulator and function test BOPE. R/U test equipment, flood and purge lines. Shell test BOPE.
Test BOPE's as per procedure witnessed by AOGCC rep Josh Hunt.
Report Number
14
Report Start Date
11/16/2023
Report End Date
11/17/2023
Operation
Cont testing BOPE at 250 psi low f/5 min, 3500 psi high f/10 min. Had two fail/pass tests, total test time 11 hrs. Had AOGCC Rep witness testing.
Removed test plug, set 9" ID wear ring, flooded stack, RU test pump on kill line and purged air, closed blinds.
Pumped 2.98 bbls (125.35 gals) to achieve 3585 psi on the 9 5/8" surface casing, held 30 minutes on chart, good test, bled back 2.98 bbls. Staged BHA componants on
catwalk while testing.
Blew down and RD test equipment, held PJSM with Sperry Reps.
MU 8 1/2" HDBS PDC bit jetted with 3x14's and 2x15's on 6 3/4" motor with 1.5° bend. MU DM and EWR-M5 collars, scribed with an RFO of 181.07°, MU ALD, CTN and
TM collars with XO and topdrive, plugged in and uploaded MWD tools, troubleshot tools, attempted to shallow pulse test, 4" valv e on mud pump two leaking, shut down,
blew down topdrive to repair 4" valve.
Repair 4" valve on mud pump #2
Shallow Pulse test. Load sources. P/U flex collars
RIH f/165' t/728' with HWDP from derrick.
RIH with DP single off catwalk f/728' t/2200'.
RIH with DP singles f/2200' t/3134'
Wash/Ream f/3134' t/3229' where tagged hard cement. Drill FE on depth. Drill rat hole cement to 3328', 390GPM=1330 PSI, 20RPM= 5.1k tq, 7k WOB,MW=9.2 PPG
ECD=9.36, P/U=96k S/O=71k ROT=81k
Report Number
15
Report Start Date
11/17/2023
Report End Date
11/18/2023
Operation
Drilled rathole cement from 3328' to 3335', then 20' new formation from 3335' to 3355'. Rot wob 1-5K, 400 gpm-1426 psi, 20 rpm-4530 to 6200 ft/lbs on bott torque, 30
ft/hr ROP, BGG 7 units.
CBU to clean up hole at 409 gpm-1348 psi, 20 rpm-5100 ft/lbs off bott torque, held PJSM with mud Engineer and CCI on displacing well, max gas 95 units. Staged trucks
at cuttings box for spud mud disposal.
Pumped 20 bbl hi-vis spacer from pill pit, lined up on pre-mix pit's, displaced well to new 9.2 ppg 6% KCL mud taking returns to cuttings box. With good mud to surface
cont to CBU twice to warm and shear mud, clean pill pit, trip tank and suction pit of spud mud. 233 gpm-452 psi, 20 rpm-5000 ft/lbs off bott torque, ECD's at 9.3, BGG 1
unit.
Racked back one stand and LD single parking bit inside casing at 3289', Blew down topdrive, MU headpin on stump, RU test equipment on drill string and kill line, purged
air, closed upper rams.
Pumped 20.7 gallons and achieved 478 psi on wellbore where it broke over, pumped an additional 11.5 gallons for a total of 32.2 . Shut down psi of 454 that bled down to
298 psi over 15 minutes. Bled back 12.5 gallons. Sent test data to Engineer, approved to drill ahead.
RD test equipment, blew down test hoses and choke manifold, lined everything up to drill, PU single and RIH 1st stand, replaced rod wash pump and mud pump #1 and
obtained SPR's with new mud and BHA in hole.
Resumed drilling 8 1/2" hole from 3355' to 3755', rot wob 4K, 438 gpm-1382 psi, 55 rpm-6072 ft/lbs on bott torque, 120 ft/hr ROP, MW 9.2/vis 49, ECD's at 9.5 ppg, BGG
44 units, max gas 316 units.
Drill 8-1/2" hole f/3755 t/4162'. 470GPM=1570 PSI, 70RPM=6.7k tq, 2-5k WOB,MW=9.3 PPG ECD=9.56, P/U=108k S/O=80k ROT=93k
Drill 8-1/2" hole f/4162' t/4378'. 470GPM=1615 PSI, 70RPM=7k tq, 5-10k WOB,MW=9.3 PPG ECD=9.59, Max gas= 473 P/U=116k S/O=83k ROT=96k
Obtain survey, CBU, SPR's, flow check well-slight seepage and blow down top drive.
POOH on elevators t/3598'. Worked through tight spot at 3715'. (30k over). Able to work through on elevators.
Report Number
16
Report Start Date
11/18/2023
Report End Date
11/19/2023
Operation
Pumped OOH to 3573', then cont pull on elevators to 3324'. S/O and parked at 3387'. Up wt 110K, down wt 75K.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 4/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
Blew down topdrive, serviced rig and topdrive, cleaned pump suction and discharge screens, checked pulsation dampners.
Picked up and singled in hole 24 joints from 3387' to 4127', then RIH on stands to 4315', no issues on TIH. MU topdrive on last stand, filled pipe, washed and reamed to
bottom. Made hook and started 20 bbl hi-vis nutplug sweep down drill string.
Cont drilling 8 1/2" hole from 4378' to 4502'. Rot wob 2-4K, 472 gpm-1673 psi, 70 rpm-7600 ft/lbs on bott torque, 80-120 ft/hr ROP, MW 9.2/vis 48, ECD's 9.5 ppg, BGG
22 units, max gas 99 units.
Cont drilling 8 1/2" hole from 4502' to 4824', rot wob 4-7K, 476 gpm-1628 psi, 70 rpm-8000 ft/lbs on bott torque, 45 to 120 ft/hr ROP, MW 9.2/vis 49, ECD's 9.6 ppg, BGG
27 units, max gas 70 units.
Drill 8-1/2" hole f/4824' t/5155'. 475GPM=1698 PSI, 70RPM=7.8k tq, 5-8k WOB,MW=9.2 PPG ECD=9.61, P/U=135k S/O=92k ROT=106k, Max gas=66
Drill 8-1/2" hole f/5155' t/5370'. 475GPM=1802 PSI, 70RPM=8.1k tq, 5-8k WOB,MW=9.2 PPG ECD=9.66, P/U=137k S/O=93k ROT=110k, Max gas=224
MWD survey. Circulate hole clean. Flow check well. Blow down top drive.
POOH on elevators t/5176'. Pulled tight (20k over) not able to work through. Pumping OOH at 5120'.
Report Number
17
Report Start Date
11/19/2023
Report End Date
11/20/2023
Operation
Cont backreaming OOH from 5120’ due to tight hole, to 4378’ (previous wiper depth). At 4752’ could not break out topdrive due to grabber not holding. Went to change
grabber dies and found internal grabber assembly broke. Cont to back ream stands, S/O to mid joint then break out topdrive holding back up with rig tongs on mid tool
joint. At 4378’ cont to pull to casing shoe on elevators while rig mechanic retrieved spare grabber assembly from warehouse. Parked string at 3264’.
Monitored well on trip tank, replaced torque relief sun cartridge on topdrive, removed grabber assembly and replaced same, func tion tested everything with no
issues.Serviced rig. Hole took 4.97 bbls over 3 1/2" hours. 3 hrs NPT for work on topdrive.
TIH from 3264' to 5298', dwn wt 75K filling pipe at 4498'. At 5298' set down twice, MU topdrive, filed pipe, washed and reamed down to slip set depth, MU topdrive on last
stand, washed and reamed to bottom at 5370', 417 gpm-1432 psi, 55 rpm-8400 ft/lbs off bott torque. No other issues TIH. Calc displacement = 41 bbls, actual
displacement = 34 bbls.
Pumped 20 bbl hi-vis nutplug sweep around at 419 gpm-1327 psi, 55 rpm-8400 ft/lbs off bott torque. Had a max of 343 units trip gas, sweep back on time, 15 to 20%
increase in cuttings.
Resumed drilling 8 1/2" hole from 5370' to 5389', rot wob 9-11K, 474 gpm-1793 psi, 75 rpm-8230 ft/lbs on bott torque, 30 to 120 ft/hr ROP, MW 9.3/vis 60, ECD's at 9.8
ppg, BGG 33 units, max gas 204 units.
Drill 8-1/2" hole f/5389' t/5649'. 446GPM=1877 PSI, 70RPM=9.7k tq, 9k WOB,MW=9.3 PPG ECD=9.75, P/U=140k S/O=98k ROT=112k, Max gas=447
Drill 8-1/2" hole f/5649' t/5903'. 446GPM=1877 PSI, 70RPM=9.7k tq, 9k WOB,MW=9.3 PPG ECD=9.75, P/U=140k S/O=98k ROT=112k, Max gas=447. Sweep in the hole
at 5863'.
Report Number
18
Report Start Date
11/20/2023
Report End Date
11/21/2023
Operation
Cont drilling 8 1/2" hole from 5903' to 6093', rot wob 7 to 10K, 474 gpm-1833 psi, 70 rpm-9200 ftlbs on bott torque, 40 to 100 ft/hr ROP. Sliding wob 7 to 16K, 474
gpm-1878 psi, 162 psi diff, 8 to 45 ft/hr ROP. MW 9.3/vis 54, ECD's at 9.8 ppg, BGG 42 units, max gas 356 units. Sweep was back on time with a 30% increase in
Cont drilling 8 1/2" hole from 6093' to 6357', rot wob 8 to 11K, 475 gpm-1953 psi, 70 rpm-10,000 ft/lbs on bott torque, 30 to 100 ft/hr ROP. Sliding wob 16K, 475
gpm-1926 psi, 118 psi diff, 25 to 70 ft/hr ROP. MW 9.4/vis 57, ECD's at 9.8 ppg, BGG 46 units, max gas 304 units.
CBU and work pipe, 474 gpm-1927 psi, 65 rpm-9703 ft/lbs off bott torque.
POOH on elevators f/6420 t/ 5830’ where assembly pulled tight(30k over). Not able to work through. Reamed t/ 5370’ 475GPM=1840PSI 30RPM=9k Tq, at which point
the hole started unloading.
Circulate and work pipe until shakers cleaned up.
Grease blocks, top drive, drawworks, iron roughneck and crown. Cleaned suction and discharge screens.
RIH on elevators f/5370' t/6420'. Disp: Calc-18.3 bbls Act-17.4 bbls.
Drill 8-1/2" hole f/6419' t/6667'. 475GPM=1698 PSI, 70RPM=10.6k tq, 5-8k WOB, MW=9.4 PPG ECD=9.92, P/U=150k S/O=103k ROT=120k, Max gas=557. Started a
sweep once back to drilling after short trip. At bottoms up hole unloaded. Sweep was back on time with a 25% increase in cuttings.
Circulate and work pipe. 285GPM=850PSI, 30RPM=9.3k Tq. Trouble shoot MP#2. MP #2 clutch on pac rim failed.
Report Number
19
Report Start Date
11/21/2023
Report End Date
11/22/2023
Operation
Racked back one stand and CBU while removing belt gaurd and drive belt on pump #2.
Pulled up hole on elevators 5 stands from 6652', blew down topdrive, cont pull up hole, up wt 173K while working on pump two and retrieving new flex coupler from
warehouse. At 5247' ran into tight hole, had to start backreaming at 290 gpm-882 psi, 70 rpm-8600 to 15,000 ft/lbs torque. At 4686' had pump 2 back together so stopped
there to test run pump.
Test ran pump 2 with no issues, put both pumps on line and CBU at 500 gpm-1888 psi, 70 rpm-7000 ft/lbs torque, rig electrician and mechanic tested and switched to a
spare wire on 37 pin cable for max torque that had been giving us problems, got that resolved. Recieved 718 sx lead cement delivered in silo.
TIH on elevators from 4686' to 6415' with no issue, dwn wt 95K. At 6415' we set down 10K twice, MU topdrive, filled pipe, washed and reamed to bottom at 6667', through
an 80' stretch of coals. Finished CBU and hole unloaded a large amount of clay and coal fragments. Had a max of 547 units gas at bottoms up. Once shakers cleaned up
shut down.
Made hook, started a 20 bbl hi-vis nutplug sweep down drill string, resumed drilling ahead from 6667' to 6790'. Sliding wob 7K, 469 gpm-2003 psi, 106 psi diff, 35 to 70
ft/hr ROP. Rot wob 10K, 475 gpm-2100 psi, 70 rpm-10,000 ft/lbs on bott torque, 100 to 120 ft/hr ROP, MW 9.5/vis 58, ECD's 9.9 ppg, BGG 63 units, max gas 521 units.
Cont drilling 8.5" production hole F/6790'-T/7132'. P/U-172K S/O-112K ROT-135K GPM-474 SPP-2127 psi RPM-70 TQ-10.8K Diff-92 psi Flow-34% WOB-10/5K MW-9.6
ppg ECD-10.1 ppg Max gas-1431 units (sand). Obtained new SPR's @ 6790'.
Cont drilling 8.5" production hole F/7132' to current depth of 7381'. Pumped Hi-Vis sweep w/ walnut & condet @7225', sweep came back 5 bbls early w/ a 60% increase
in cuttings. P/U-183K S/O-115K ROT-137K GPM-480 SPP-2187 psi RPM-70 TQ-11.3K Diff-264 psi Flow-34% WOB-10/5K MW-9.6 ppg ECD-10.1 ppg Max gas-365
units. Distance to well plan: 8.31' 8.06' High 2.02' Right.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 5/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Report Number
20
Report Start Date
11/22/2023
Report End Date
11/23/2023
Operation
Cont drilling 8 1/2" hole from 7381' to TD at 7703' md/7325' tvd. Rot wob 10K, 480 gpm-2200 psi, 70 rpm-10,900 to 12,000 ft/lbs on bott torque, 80 ft/hr ROP. MW 6.5+/vis
53, ECD's 10.3 ppg, BGG 61 units, max gas 461 units. At TD we are us 1.24’ low and 2.16’ right of the line .
CBU one time at 478 gpm-2121 psi, 70 rpm-11,300 ft/lbs off bott torque and cont to dust up MW to a 9.8 ppg. Followed CBU with a 20 bbl hi-vis nutplug sweep and added
1 drum NXS lube to spot on backside for wiper trip. Sweep back 6 bbls early and 25% increase in cuttings.
Obtained SPR's, did a 30 minute flow check: 1st 10 min flow at .27 bph, 2nd 10 minflow at .15 bph, 3rd 10 min no flow.
Pulled up hole on elevators, up wt 180K, dwn wt 125K, from 7700' to 7092' and seeing tight hole. Pulled three times with no pro gress. MU topdrive and began
backreaming from 7092' to 6901' at 478 gpm-2208 psi, 70 rpm-10,000 to 19,000 ft/lbs torque, 6" to 3' intervals or topdrive woul d stall.
Cont backreaming from 6901' to 6667' (previous wiper depth for pump repair)
CBU at 500 gpm-2234 psi, 80 rpm-10,400 ft/lbs working stand, to clean up hole.
Attempted to POOH on elevators w/ no luck. BROOH F/6532' to current depth of 3833', working through multiple areas w/ high torq ue. P/U-135K S/O-132K ROT-128K
GPM-480 SPP-1938 psi RPM-80 TQ-10/18K MW-9.85 ppg ECD-10.6 ppg Max gas- 414 units. Distance to well plan: 2.49' 1.24' Low 2.16' Right.
Report Number
21
Report Start Date
11/23/2023
Report End Date
11/24/2023
Operation
Cont to BROOH from 3833' to 3321', hole much better at 3780'. 487 gpm-1859 psi, 70 rpm-9500 to 16,000 ft/lbs torque
CBU at 3321' with bit just outside casing shoe, 484 gpm-1678 psi, 35 rpm-4800 ft/lbs torque, max gas 15 units. No noticable increase in cuttings.
Monitored well on trip tank, blew down topdrive, hung off blocks, cut and slipped 95' drill line, calibrated hookload and block height, inspected derrick, checked turnbuckles
on torque tube, loss rate at .80 bph
TIH on elevators from 3321' to 5052' and filled pipe, down wt 75K. Cont TIH, up wt 145K, dwn wt 90K, to 6168' and set down 3 times (coal into sandstone) then passed
through. At 6360' washed/reamed to 6418'. At 6475' washed/reamed to 6480'. At 6720' washed/reamed to 6726', at 6957' washed/reamed to 6972', at 7065'
washed/reamed to 7096', at 7230' washed/reamed to bottom due to fresh cut tight hole. 489 gpm-2348 psi, 70 rpm-8600 to 19,000 ft/lbs torque. At 7340' hole unloaded
and gas maxed out at 3657 units. Rotated/reciprocated stand until gas dropped to 240 units.
Pumped 20 bbl hi-vis nutplug sweep around at 487 gpm-2348 psi, 70 rpm-10,700 to 11,000 ft/lbs torque. Sweep back 1000 stks late and 10% increase. Cont to circulate
surface to surface one more time to get shakers to clean up. Gas at 70 units at shut down. MW at 9.9 ppg.
Did 30 min flow check, loss rate at 1 bph.
L/D single to change breaks. POOH on elevators F/7703'-T/3863' w/ no issues P/U-190K S/O-123K. Dropped metal drift on wire w/ 50 stds to go @ 3863'. Perform weekly
BOP function test. Resumed POOH on elevators F/3863'-T/3555'.
Crew change, held PTSM. Cont. POOH on elevators w/ no issues F/3555' to casing shoe @ 3317'.
Flow checked well at 9-5/8" casing shoe for 15 min. Static loss rate = 1 bph.
Resumed POOH F/3317'-T/BHA #2.
Racked back HWDP, L/D jars std, and flex collars. Calculated hole fill = 55.4 bbls Act =69.1 bbls Diff = 13.5 bbls. Gave TRS 3 hr. notice.
Held PJSM, and removed sources from BHA #2.
Downloaded MWD data.
Currently L/D remainder of BHA #2.
Report Number
22
Report Start Date
11/24/2023
Report End Date
11/25/2023
Operation
LD motor and bit, bit graded 3-1 and in gauge.
Cleaned and cleared rig floor and catwalk, staged casing tongs, elevators and slips on floor, staged centralizers and fill hose, held PJSM.
MU and filled 4 1/2" shoe track, checked floats functioned properly, PU and singled in hole from 123' to 1406', torqued to 617 0 ft/lbs, filling on the fly, topping off every 10
jnts.
Cont PU single in hole from 1406' to 3294' (80 jnts) just above surface shoe. Cleaning pre-mix pits.
MU circ swedge and topdrive, ease into circulating staging up to 4.5 bpm at 147 psi, staged liner extension assembly on catwalk. Max gas 35 units.
Cont PU single in hole from 3294' to 4568'. Up wt 55K, dwn wt 50K.
Swap to 7" elevators, PU lower SBR assembly and MU same on 4 1/2" stump, torque first two connections with rig tongs along w/ r emaining 7" conections. P/U Baker
SLZXP(HRD-E) liner hanger, M/U PBR pack-off assy to bottom of running tail. Run PBR pack off inside SBR assy. M/U hanger to SBR w/ rig tongs. Mixed and poured
Zan-plex into TOH. M/U XO & 1 std. of 4.5" DP to top of running tool. RIH and CBU @ 4651'. GPM-189 SPP-250 psi. Set drill TQ on TD to 9.5K. Obtained rotary TQ
values @ 10 RPM-2.4K 20 RPM-2.7K 30 RPM-3.1K
Cont. RIH w/ liner/hanger on 4.5" DP @ 10-15 fpm F/4651'-T/6154' w/ no issues.
M/U TD, broke circulation. Staged up MP, CBU @ 6154'. GPM-176 SPP-274 psi MW-9.9 ppg Max gas-232 units.
Cont. RIH F/6154'-T/7504'. Started washing down @ 7504' due to tight spots. Current depth of 7652'. P/U-110K S/O-90K GPM-112 SPP-290 psi.
Report Number
23
Report Start Date
11/25/2023
Report End Date
11/26/2023
Operation
Cont washing last couple stands down from 7652' and tagged bottom on depth at 7703', 111 gpm-299 psi, up wt 130K, dwn wt 95K. Racked abck stand 50, PU kelly joint
and 10' pup, MU cement head and topdrive.
Circulated staging up to 258 gpm (6 bpm)-744 psi, 22% flow, max gas 3065 units. Cont to circ until gas down to 200 units, shut down and RU cement lines to cement
head, installed sheave and winch line for rotating. Held PJSM with rig team and cementers, batched up spacer.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 6/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
Halliburton pumped 10 bbls water to flush and fill lines. Shut in at Baker cement head and PT lines at 600 psi low 4400 psi high. Good tests.
Lined up and pumped 34 bbls 10.5 ppg Tuned Spacer at 4 bpm-400 to 340 psi, 15.6% flow, followed with 312 bbls (718 sx) 12 ppg Type I II Lead cement at 5 bpm-340 to
131 psi, 18% flow. 250 bbls into lead cement we lost returns while reciprocating. Began rotating at 20 rpm-6700 to 7400 ft/lbs surface torque and flow came back.
Followed lead with 37 bbls (180 sx) 15.3 ppg Type I II Tail cement at 3 bpm- 131 to 160 psi, 14.3% flow. Had 2.4 pps Bridgemaker LCM in lead. Baker released dart,
Halliburton then displaced with 9.9 ppg 6% KCL mud at 5 bpm-112 psi ICP, up wt 140K, dwn wt 95K. Saw dart latch wiper plug 40 b bls into displacement as pressure
increased from 41 psi to 589 psi at 2 bpm. Once plug released pressure dropped and we resumed 5 bpm. With 16 bbls to go, reduced rate to 3 bpm-1100 psi, parked
string and stopped rotating. Bumped liner wiper plug/landing collar 107.5 bbls into displacement (calculated at 111 bbls). FCP 1100 psi. Halliburton increased to and held
1836 psi (736 over fcp) for 2 minutes, then increased pressure to 2610 psi for 2 minutes to set hanger and packer, saw a 5K decrease in string weight on weight indicator.
Pressured up to 3800 psi to neutralize hyd set tool for 1 minute.
Bled back 1.5 bbls to truck and floats held. Slacked off on blocks from 115K to 25K giving us a good indication hanger and packer were set, PU wt 75K giving us good
indication we had released run tool. CIP at 11:36 on 11-25-23. No losses.
R/D cement hoses and L/D Baker cement head. M/U TD to stump to circulate. Pressured up to 877 psi on drill string and PU 10’, string pressure started dropping, ramped
up both pumps and CBU twice at 486 gpm-696 psi. Had 34 bbls spacer and 50 bbls cement/contaminated mud at the shakers. RD shacks and released GeoLog and
Sperry Reps.
LD 10' pup and single jnt, POOH from 3084', inspected, broke down and LD run tool.
PU cement head and broke off rig's XO's and pup joints. PU kelly joint and diffuser, flushed BOP stack with black water, functioned rams and flushed again. LD diffuser
and blew down topdrive.
PU Baker "SBR" polish mill, 34.88' long, 4.65" lower "TBR" mill. MU XO and TIH on stands to 3073'. Washed down and tagged up on XO below PBR @ 3125', putting
TOL @ 3089'. (Sent AOGCC 24 hr notification for MIT-T/MIT-IA)
P/U 8.5' and made mark on DP. Dressed 8.5' of PBR as per Baker rep. P/U-55K S/O-55K GPM-127 SPP-173 psi RPM-30 TQ-2.8K.
CBU @ 3124'. GPM-241 SPP-351 psi MW-9.85 ppg. Held PJSM on displacement w/ rig crew, Baroid, and drill support.
Lined both MP's, Pumped 20 bbl Hi-Vis spacer, followed by 210 bbls CI 6% KCL brine to displace well. GPM-224 SPP-433 psi. Shut down pumps, removed shaker
screens, cleaned shaker beds and ditches. Performed 30 min negitive test/Flow check (ok).
POOH L/D 4.5" CDS-40 DP F/3124'-T/2787'.
Rig service- Greased & inspected crown, blocks, TD, wash pipe, IR, DWKS, brake linkage, and drive line.
Resumed POOH L/D 4.5" DP singles F/2787', currently L/D Baker polish assy.
Report Number
24
Report Start Date
11/26/2023
Report End Date
11/27/2023
Operation
MU muleshoe on DP and RIH from derrick to 2478'.
MU topdrive and circulate string volume, then blew down topdrive.
POOH LD singles from 2478', taking the time to steam clean threads and inspect same, vac wiper ball through joints on pipe rack , dry and re-dope threads and re-install
thread protectors.
PU single HWDP jnt and kelly jnt, cont RIH on remaining stands from derrick to 1831'.
MU topdrive and circ pipe volume, blew down topdrive, Cont hauling excess mud from pits to G&I (5 to 6 hour round trip due to icy conditions, trucks having to chain up
including steering tires to come in field, or chains off to travel highway)
POOH LD remainder of DP, cont cleaning and inspecting threads, vac wiper balls and re-doping threads, install thread protectors. RU plumbing on new test pump for
testing casing when OOH.
String test hoses, RU on mezz kill and chart recorder, purged air.
Performed liner lap test T/3500 psi on a chart for 30 min (Good test). Pumped in - 3.77 bbls Bled back - 3.72 bbls. BLM rep arrived on location @ 21:00 hrs to do only a
site inspection (all looked good).
R/D testing equip. & blew down lines. M/U test plug & XO to 1 jt. of DP, pulled wear ring and L/D same. M/U well head brush & XO to 1 jt of DP, flushed & brushed out
well head, L/D same.
Cleaned & cleared rig floor. R/U TRS equip. Loaded up catwalk racks w/ 4.5" tubing. Held PJSM on running tie back. Cont. hauling off drilling mud and cleaning tank
bottoms.
M/U Baker bullet seals to bottom of first tubing jt. Cont. running 4.5" 12.6# TXP L-80 tie back tubing as per run tally F/surfa ce-T/1021'.
Crew change, held PTSM. Cont. running 4.5" 12.6# TXP L-80 tie back tubing as per run tally F/1021'. Tagged XO below PBR @ 3123.49'. POOH, L/D tag jts. and top jt.
M/U space out pups to bottom of top jt. (Pups A, B, C, and E = 34.23'). Putting us 1.33' off XO. P/U & M/U hanger pup, hanger, and LJ to stump. Drained stack, and
Landed out hanger. WHR perform pre pressure test, locked in hanger, and performed post pressure test.
Currently R/U to perform MIT-T & MIT-IA T/3500 psi on chart for 30 min as per BLM & AOGCC regulations.
Report Number
25
Report Start Date
11/27/2023
Report End Date
11/28/2023
Operation
Start MIT-T and at 1800 psi had to shut down and bleed off due to leak in test pump plumbing. Made repairs, pumped 1.36 bbls to achieve 3600 psi on tubing, held 30
min, good test. RU on IA and pumped 2.3 bbls to achieve 3600 psi on IA, held 30 min, good test.
RD test equipment, RD tubing tongs, B/O landing joint and removed from rig floor. Wellhead Rep installed 2 way check. Cont cleaning pits (still 6 hr turn around on trucks
to G&I)
Flushed BOP stack, choke manifold, surface lines and pumps with BaraKlean solution, followed with fresh water then blew everything down. Expediter met with
Production Foreman and A&L Rep on plan to bring next pad up to grade for rig footprint.
Opened BOP ram doors, inspected rams and cavities, greased everything then buttoned up doors, loaded Baker equipment for return to slope, checked topdrive end play,
changed oil in rotary table-topdrive gear box and swivel, RD gen 3 skid, inspected valves/seats in mud pumps, removed BOP stack from wellhead.
WHR installed lower section of tree. Tested neck seals, void, and tree T/5000 psi for 15 min (ok). Changed out oil in DWKS chain case, and DWKS right end gear box.
Replaced hose on degasser HYD cylinder.
Cont. cleaning out tanks bottoms in pit system, power washing of rig, loading out of misc. equip/materials and hauling to staging pad.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 7/7
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
Crew change, held PTSM. Cont. working on cleaning & R/D. R/D and L/O service shacks, R/D pop off lines, bleeder line, and suction line between pits & MP's. Secured
shakers for travel. R/D Pason stand alone gas trap, and MGS hard lines. Finished cleaning pit system. R/D IR HPU, TD HPU lines, and koomey lines between sub &
koomey house. Lowered degasser vessel into pit #4. Removed bails & elevators from TD. Sent handling equip., XO's, and subs off rig floor. R/D Kelley hose & service
loop for TD. R/D & L/D TQ bushing, and TD. Cont. with cleaning, R/D, and prepping for move.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #:
State: ALASKA
Rig/Service: HEC 169
Page 1/2
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:12/1/2023 End Date:
Report Number
1
Report Start Date
12/1/2023
Report End Date
12/2/2023
Operation
Mobilze coil Unit and Crew From Fox yard to SRU 232-15.
JSA & permit with Operator Arrive on location, check location
Spot equipment in place & Rig Up.
Fill up surface lines and BOPs.
Start BOP test. Test BOP's per sundry to 250 low /3500 psi high. 24 Notification given to the AOGCC on 11/30 @ 12:00. Witness waived by Jim Regg Via email.
BOP test complete: RU fluid pump
Secure well. Unit on standby for the night. Crew off location.
Rig on standby for daylight ops
Report Number
2
Report Start Date
12/2/2023
Report End Date
12/3/2023
Operation
Mobilize crew from Yard to SRU office.
JSA & permit with Operator. FOX, Cruz & Yellow jacket conduct JSA for upcoming work
Arrive on location, Warm up equipment.
Pick up Injector. Stack Lubricator. BOP's are nippled up & Function Tested.
Trim 100' of pipe. MU YJ 1.75" x 2-3/8" External CTC. Pull Test 25k
Online for fluid pack W/warm water
PT MHA 3500psi - Good Test. MU Milling BHA.
On well. PT stripper and lube 250 low 3500 psi 5 min each
Good Low / High PT. Test DHCV's. Good Tests.
RIH w/ YJ 1.75" x 2-3/8"' CTC, 2.88" x 1.25' DBPV, 2.88" x 6.10' bi-Di Jar, 2.88" x 2.12' TJ Disco (3/4" ball seat), 2.88" x 1.20' Circ-Sub (5/8" ball seat), 2.88" x 12.70'
Mud Motor, 3.13" x .50' XO. 3.75" HC Tri-Cone Bit. OAL= 25.27' / Max OD= 3.75" Open choke & take pipe disp returns
RIH wt 9K, PUW 17500 at 5000'.RIH at ~125 ftm
PUW at 7,500' 22K. RIH wt 11K.
Tag up at 7575. Kick on pump, wash down to PBTD
RIH, Wash down to 7626'md. Tag up with 500-1000 lbs. Observe Slight TQ
PU off bottom, Circulate well over to produced water. While pooh. SD pump at 750'. Good clean water at surface.
Bump up. Swab check. LD BHA & cut CTC off.
RIH to 500'. Pump N2 to displace down to 500' N2 pump offline. Hooh up heater to thaw.
Spot YJ eline Unit. On location at 16:30. Prep for CBL.
Vac trucks haul off 160 bbls
Online with N2, evacuate well from 500'. POOH with Coil
Bump up. Swab check.
Break off, LD injector and Lub's
SD Unit & LD for the night- Crew leaving Location
MU Logging BHA.
RIH with CBL tools. Tag PBTD. ~7615'
Make repeat log pass from 7615' - 7190'
Report Number
3
Report Start Date
12/2/2023
Report End Date
12/3/2023
Operation
Report Number
4
Report Start Date
12/3/2023
Report End Date
12/4/2023
Operation
Mobilize crew from Yard to SRU office.
JSA & permit with Operator. FOX, Cruz & conduct JSA for todays well work.
Pick up Injector. Stack Lubricator. BOP's are nippled up & Function Tested.
MU Roll on CTC & 2-1/8" Nozzle with 1" Port.
RIH with Nozzle. Pumping N2 to blow well dry.
Tag PBTD with 5K down at 7625' PU to 7619'. Cont Pumping N2. N2 to surfce. Verify Flow back tank measurements. Well blown dry Recovered ~116 bbls total.
POOH,Start Rigging down. Bump up, swab check. Shut well In trapping ~2450 psi on the well.
Start the Rig down process. Break off Lube and Injector. LD. Secure well, Install Night Cap.
Complete RDMO, Fox Coil 8. Notify Lead operator of well condition.
Report Number
5
Report Start Date
12/6/2023
Report End Date
12/7/2023
Operation
Watched short time for build up. Building but slow to 2289 BHP. POOH w/ GPT.
Yellow Jacket travel to Swanson River office. PJSM & permit. Travel to P&S pad. Fire & warm equipment. Travel to loacation.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #: 323-644
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-091
Page 2/2
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024www.peloton.com
Well Operations Summary
Operation
MIRU. Call for heater to thaw out frozen pack off equipment. Complete rig up.
PT 250 / 3500 PSI. Test good.
RIH w/ GPT. Tag fill at 7615'. No FL detected. Sent GPT log to town. POOH.
RIH w/ Gun ONE.
Made tie in pass. Sent log to town. Town approved.
Position Gun ONE to shoot TY 68 Zone at 7551' to 7570'. CCL to TS = 11' / CCL to be at 7540' to place TS at 7551'. POOH. Start PSI: 2379 / 5 Min 2368 / 10 Min 2366 /
15 Min 2365 / 20 Min 2360 / 25 Min 2359 / 30 Min 2357
OOH. L/D Gun ONE. All shots fired. End cap dry.
Turn well over to production to flow test. Production lining out well. YJ prepping GPT to re-run.
RIH w/ GPT. At 3000' production was ready & began to flow well. Start PSI 2350. Brought down to 1800 PSI. SI well.
Watched short time for build up. Building but slow to 2289 BHP. POOH w/ GPT.
OOH. L/D GPT. Secure equipment & night cap well. Return to YJ shop. Plan Forward: Production to draw well down to 1500 PSI then SI for a build up. YJ to return in
morning for anticipated GPT run & possibly perf next zone.
Report Number
6
Report Start Date
12/7/2023
Report End Date
12/8/2023
Operation
Travel to Swanson River from YJ shop.
PJSM & Permit.
Travel to loacation. Fire & warm equipment.
RIH w/ GPT. Tag fill at 7614'. No change from yesterday. No FL detected. POOH.
RIH w/ Gun TWO. Production rigged up to inject gas down tbg.from 1472 PSI to 2200 PSI.
Made tie in pass. Sent log to town. Town approved. Tubing PSI at 2206. Gas injection stopped.
Position Gun TWO to shoot TY 64-5 Zone at 7233' to 7251'. CCL to TS = 10' / CCL to be at 7223' to place TS at 7233'. Fire Gun T WO. POOH. Start PSI: 2206 / 5 Min
2202 / 10 Min 2201 / 15 Min 2199 / 20 Min 2197 / 25 Min 2194 / 30 Min 2193.
OOH. L/D Gun TWO. All shots fired. End cap dry. P/U GPT.
RIH w/ GPT while production flow tests well. Tag fill at 7614'. No change. FL detected at 7588' with tubing at 1868 PSI.
POOH w/ GPT. Production SI well & start gas injection down tubing.
OOH. L/D GPT. P/U Gun THREE 20' x 2.75" GEO Razor XDP 15 Gram shots 6 SPF.
RIH w/ Gun THREE. Production still pressuring up tubing. Stopped injection at 2322 PSI.
Position Gun THREE to shoot TY 62-5 Upper Zone at 6977' to 6997'. CCL to TS = 10' / CCL to be at 6967' to place TS at 6977'. Fire Gun THREE. POOH. Start PSI: 2312
/ 5 Min 2312 / 10 Min 2311 / 15 Min 22309 / 20 Min 2307.
OOH. L/D Gun THREE. All shots fired. End cap dry.
Secure equipment & night cap well.
Return to YJ shop. Plan Forward: Production to draw well down to 1000 PSI at 1 mmscfd. YJ to return in morning for anticipated GPT run & perf rest of TY 62-5 zone.
Report Number
7
Report Start Date
12/8/2023
Report End Date
12/9/2023
Operation
Yellow Jacket travel to Swanson River office. PJSM & permit. Travel to loacation. Fire & warm equipment. MIRU YJ.
Set up Gun FOUR. 16' x 2.75" GEO Razor XDP 15 Gram shots 6 SPF to shoot lower TY 62-5 zone 6997' to 7013'.
RIH w/ Gun FOUR. Well is flowing at 1873 PSI.
Made tie in pass. Sent log to town. Town approved.
Unshot Gun FOUR sticky through existing perfs. OE advised SI well for 1/2 hour & try passing again.
Pad Op SI well. Re-drifted through existing perfs. All good.
Position Gun FOUR to shoot TY 62-5 Lower Zone at 6997' to 7013'. CCL to TS = 14' / CCL to be at 6983' to place TS at 6997'. Fir e Gun FOUR. POOH. Start PSI: 2226 /
5 Min 2285 / 10 Min 2301 / 15 Min 2313. Pad Op brought on well while POOH.
OOH. L/D Gun FOUR. All shots fired. End cap dry. P/U GPT.
RIH w/ GPT while production flow tests well. Tag fill at 7614'. No change. FL detected at 7487. POOH w/ GPT.
OOH. L/D GPT. RDMO YJ E-Line.
API: 50-133-20714-00-00 Field: Swanson River
Sundry #: 323-644
State: ALASKA
Rig/Service:
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(#BE (#B
B
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.11.28 11:34:34 -09'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.11.28 11:40:31 -09'00'
Page 1/1
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024
www.peloton.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
7,703.00 Original KB/RT Elevation (ft):
334.80
RKB to GL (ft):
18.00 KB-Casing Flange Distance (ft):
21.97 KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
7,617.8
Casing
Casing Description:
Surface Run Date:
11/14/2023 Set Depth (ftKB):
3,318.67
Casing Weight on Slips (1000lbf): Pick Up Weight (1000lbf):
140,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
15.50 Ft/Min (ft/min):
3.57
Run Job:
231-00059 SRU 232-15 Drilling, Drilling -
Drilling, 11/3/2023 06:00
Set Depth (ftKB):
3,318.67 Set Depth (TVD) (ftKB):
3,166.7
Centralizer Detail:
Every Other Joint up to 300'
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)
1 Casing Hanger 15 8.68 47.00 BTC 1.21 22.85 21.64
81 Casing Joints 9 5/8 8.68 47.00 L-80 BTC 3,214.89 3,237.74 22.85
1 Float Collar 10 3/4 8.68 BTC 1.38 3,239.12 3,237.74
2 Casing Joints 9 5/8 8.68 47.00 L-80 BTC 77.78 3,316.90 3,239.12
1 Float Shoe 10 3/4 BTC 1.77 3,318.67 3,316.90
Page 1/1
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024
www.peloton.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 3,318.67ftKB
Wellbore
Original Hole
Job
231-00059 SRU 232-15 Drilling, Drilling -
Drilling, 11/3/2023 06:00
Cementing Start Date
11/15/2023
Cementing End Date
11/15/2023
Top Depth (ftKB)
26.0
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
26.0
Bottom Depth (ftKB)
3,335.0
Top Measurement Method
Returns to Surface
Pump Start Date
11/15/2023
Cement in Place At
11/15/2023
Final Circulating Pressure (psi)
850.0
Plug Bump Pressure (psi)
1,580.0
Full Return?
Yes
Returns During Job (%)
98
Volume to Surface (bbl)
60.7
Volume Lost (bbl)
20.0
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)10.50 60.0 60.0 4 Cement unit
Lead Slurry A 565 2.44 12.00 259.0 243.0 5 Cement unit
Tail Slurry A 255 1.16 15.80 52.0 50.0 4 Cement unit
Displacement 9.40 240.7 237.4 3
Post Job Calculations
Subtype Value
Page 1/1
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024
www.peloton.com
Casing
uiner 1
Wellf ore
Wellf ore Name:
Original Hole botal TeptDohWellf ore (htKB):7,703.00 Original KB/Rb Elevation (ht):334.80
RKB to Gu (ht):18.00 KB-Casing Flange Tistance (ht):21.97 KB-bLf ing Hanger Tistance (ht):
PBbTs
TeptD(htKB):7,617.8
Casing
Casing Tescription:
Liner 1 RLn Tate:
11/24/2023 Set TeptD(htKB):7,701.00
Casing WeigDt on Slips (1000lf h):40,000.0 Pick Up WeigDt (1000lf h):130,000.0 Block WeigDt (1000lf h):15,000.0
Make-Up Contractor:
Parker Casing NLmf er Hrs to RLn (Dr):
22.00 Ft/Min (ht/min):5.83
RLn Jof :
231-00059 SRU 232-15 Drilling, Drilling -
Drilling, 11/3/2023 06:00
Set TeptD(htKB):7,701.00 Set TeptD(bVT) (htKB):7,323.3
Centralizer Tetail:
Every Joint first 60 then every other to surface shoe
Attrif Lte SLf type: ValLe:
Pipe Reciprocated?:
Yes Pipe Rotated?:
Yes Float Failed?:
No
best SLf type:
Liner Hanger PressLre (psi):
3,500.0
Casing (Or uiner) Tetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
2 Liner Hanger 8.42 4.75 BAKER OIL
TOOLS
38.26 3,127.51 3,089.25
62 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 2,460.13 5,587.64 3,127.51
1 RA Marker Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 39.73 5,627.37 5,587.64
12 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 477.26 6,104.63 5,627.37
1 Marker Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 20.01 6,124.64 6,104.63
12 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 476.77 6,601.41 6,124.64
1 RA Marker Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 40.13 6,641.54 6,601.41
12 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 479.41 7,120.95 6,641.54
1 Marker Pup Joint 4 1/2 3.96 12.60 L-80 TXP-BTC 20.01 7,140.96 7,120.95
12 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 476.87 7,617.83 7,140.96
1 Landing Collar 5.05 TXP-BTC JHOBBS 1.05 7,618.88 7,617.83
1 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 39.13 7,658.01 7,618.88
1 Float Collar 5.05 TXP-BTC JHOBBS 1.46 7,659.47 7,658.01
1 Blank Liner 4 1/2 3.96 12.60 L-80 TXP-BTC 39.73 7,699.20 7,659.47
1 Float Shoe 5.05 TXP-BTC JHOBBS 1.80 7,701.00 7,699.20
Page 1/1
Well Name: SRF SRU 232-15
Report Printed: 1/3/2024
www.peloton.com
Cement
Liner Cement
Type
Casing
Description
Liner Cement
Cemented String
Liner 1, 7,701.00ftKB
Wellbore
Original Hole
Job
231-00059 SRU 232-15 Drilling, Drilling -
Drilling, 11/3/2023 06:00
Cementing Start Date
11/25/2023
Cementing End Date
11/25/2023
Top Depth (ftKB)
3,089.3
Cement Stages
Stage Number: 1
Description
Liner Cement
Top Depth (ftKB)
3,089.3
Bottom Depth (ftKB)
7,703.0
Top Measurement Method
Returns to Surface
Pump Start Date
11/25/2023
Cement in Place At
11/25/2023
Final Circulating Pressure (psi)
1,100.0
Plug Bump Pressure (psi)
1,836.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
50.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
Yes
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) Tuned 3.82 10.50 34.0 34.0 4 Halliburton
Lead Slurry Type I II A 718 2.39 12.00 312.0 312.0 5 Halliburton
Tail Slurry Type I II A 180 1.24 15.30 37.0 37.0 3 Halliburton
Displacement 6% KCL 9.90 107.5 111.0 5 Halliburton
Post Job Calculations
Subtype Value
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: 12/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
SRU 232-15
PTD: 223-091
API: 50-133-20714-00-00
FINAL LWD FORMATION EVALUATION LOGS (11/11/2023 to 11/22/2023)
EWR-P4, EWR-M5, DGR, AGR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-091
T38225
12/14/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.14
16:10:29 -09'00'
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/13/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
SRU 232-15
PTD: 223-091
API: 50-133-20714-00-00
FINAL MUDLOGS - EOW DRILLING REPORTS (11/11/2023 to 11/22/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
a. Formation Log
b. LWD Combo Log
c. Gas Ratio Log
d. Drilling Dynamics Log
Folder Contents:
Please include current contact information if different from above.
PTD: 223-091
T38222
12/14/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.12.14
10:17:32 -09'00'
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Chad Helgeson
Cc:Donna Ambruz
Subject:RE: [EXTERNAL] SRU 232-15 (PTD 223-091) initial perf sundry
Date:Wednesday, December 6, 2023 12:09:00 PM
Chad,
Hilcorp has approval to proceed with the perforations based on the log indicating good cement bond
across the interval.
Regards
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: Wednesday, December 6, 2023 11:48 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: RE: [EXTERNAL] SRU 232-15 (PTD 223-091) initial perf sundry
Bryan,
Thanks for helping us get the approved sundry for SRU 232-15.
In the sundry it states that we need to submit the CBL and obtain approval to perforate. I sent this
to you on Sunday.
Do we have approval to perforate based on the CBL results. See email below. Or if I need to send the
CBL to you again.
Chad
From: Chad Helgeson <chelgeson@hilcorp.com>
Sent: Sunday, December 3, 2023 1:40 PM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Subject: RE: [EXTERNAL] SRU 232-15 (PTD 223-091) initial perf sundry
Bryan,
Please find attached the CBL for SRU 232-15. I am not sure if you are going to require seeing this
before we get approval to perforate.
Attached is the CBL which has good bond to 3102’. Hopefully the Sundry is approved tomorrow so
we can perforate on Tuesday.
Let me know if you have any questions or need additional information.
Chad
From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Sent: Thursday, November 30, 2023 1:17 PM
To: Chad Helgeson <chelgeson@hilcorp.com>
Cc: Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC)
<steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL] SRU 232-15 (PTD 223-091) initial perf sundry
Chad,
Hilcorp has verbal approval to complete the CT portion of the work, steps 1-11 listed in your sundry
application submitted on 11/28/23. FYI, this will be sundry # 323-644 once issued.
Regards
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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
From:McLellan, Bryan J (OGC)
To:chelgeson@hilcorp.com
Cc:Roby, David S (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC)
Subject:SRU 232-15 (PTD 223-091) initial perf sundry
Date:Thursday, November 30, 2023 1:16:00 PM
Chad,
Hilcorp has verbal approval to complete the CT portion of the work, steps 1-11 listed in your sundry
application submitted on 11/28/23. FYI, this will be sundry # 323-644 once issued.
Regards
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
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):
7,703'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,750psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
LTP; N/A 3,909' MD/ 2,949' TVD; N/A, N/A
7,325'7,618'7,240'
Swanson River Tyonek Gas
16"
9-5/8"
See Attached Schematic
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Swanson River Unit (SRU) 232-15CO 716A
Same
7,321'4-1/2"
2,986'
4,611'
N/A
Length
December 11, 2023
Tieback 4-1/2"
7,701'
Perforation Depth MD (ft):
See Attached Schematic
2,980psi
6,870psi
120'120'
3,318'
Size
120'
3,318'
MD
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
3,123'
8,430psi
3,165'
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
FEDA028406/FEDA028384
223-091
50-133-20714-00-00
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Chad Helgeson, Operations Engineer
AOGCC USE ONLY
Tubing Grade:
chelgeson@hilcorp.com
907-777-8405
Noel Nocas, Operations Manager 907-564-5278
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n 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
By Grace Christianson at 8:11 am, Nov 28, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.11.27 16:05:20 -
09'00'
Noel Nocas
(4361)
323-644
CT BOP test to 3500 psi.
Submit CBL to AOGCC and obtain approval to perforate.
DSR-11/29/23
10-407
Yes 11/30/23 for CT Ops
Bryan McLellan 12/5/23 for remainder
X
A.Dewhurst 05DEC23BJM 11/30/23
*&:
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.12.06 10:27:26
-09'00'
RBDMS JSB 120723
Initial Completion
Well: SRU 232-15
Well Name: SRU 232-15 API Number: 50-133-20714-00-00
Current Status: New Drill Gas Producer Permit to Drill Number: 223-091
First Call Engineer: Chad Helgeson (907) 229-4824 (c)
Second Call Engineer: Ryan Rupert (907) 301-1736 (c)
Maximum Expected BHP: 3,706 psi @ 7,199’ TVD 9.9ppg at TD
Max. Potential Surface Pressure: 2,986 psi Using 0.1 psi/ft
Brief Well Summary
SRU 232-15 was drilled with Hilcorp Rig 169 in November 2023 targeting Beluga and Tyonek sands in the north
block of Swanson River Field. The well was TD’d, casing cemented and liner run this past weekend. The objective
of this sundry is to clean out the liner with coil tubing, complete a CBL, remove fluid from well bore and perforate
sands working from the bottom of the well. Initial targeted sand will be in the Tyonek gas Pool/PA.
Wellbore Conditions:
The rig has left the liner full of 9.9 ppg drilling mud, with the tubing and annulus displaced to 6% KCL, and
pressure tested tubing and annulus to 3500 psi for 30 min.
Coiled Tubing Procedure
1. MIRU Coiled Tubing and pressure control equipment
2. PT lubricator to 250psi low / 3500psi high
a. Provide AOGCC and BLM 24hr notice for BOP test
3. MU cleanout BHA
a. Motor and roller cone bit for cement stringers
4. RIH to PBTD (7,816’) cleanout well and swap well over to water
5. RU Eline on coil BOPs
6. PT lubricator to 2500 psi
7. Log CBL
8. RDMO EL
9. CT RIH with nozzle and blow well dry with nitrogen
a. Reverse circulate water out of wellbore (no perforations, passing MIT’s)
b. Target recovery = 115bbls
i. Tubing Volume: 48bbls
ii. Liner volume: 68 bbls
10. Trap ~2500 psi of N2 on wellbore (confirm with OE for final pressure left on well)
11. RDMO CT
12. MIRU E-line and pressure control equipment
13. PT lubricator to 250psi low / 3500psi high
14. RIH and perforate per RE/Geo (see table below)
Initial Completion
Well: SRU 232-15
Sands Top MD Btm MD Top TVD Btm TVD FT
TY_61-0 ±6,636' ±6,645' ±6,313' ±6,322' ±9'
TY_61-8 ±6,748' ±6,780' ±6,418' ±6,450' ±32'
TY_62-3 ±6,868' ±6,895' ±6,531' ±6,558' ±27'
TY_62-5 ±6,977' ±7,013' ±6,633' ±6,669' ±36'
TY_64-5 ±7,233' ±7,251' ±6,876' ±6,894' ±18'
TY_67-0 ±7,446' ±7,469' ±7,079' ±7,103' ±24'
TY_68-0 ±7,551' ±7,570' ±7,180' ±7,199' ±19'
15. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist.
a. Record initial and 5/10/15 minute tubing pressures after firing
b. Above perfs will be shot in the Tyonek Gas Pool governed by CO 716A
16. RD E-Line Unit and turn well over to production
17. Operations to flow well and test zones
18. Test SVS as per 20 AAC 25.265 once stable flow is achieved
a) Notify AOGCC 24hrs in advance of testing SVS
E-line Procedure (Contingency)
If any zone produces sand and/or water or needs isolated:
19. MIRU Eline and N2 pump truck
20. Pressure test equipment to 3,500 psi High/250 psi Low
21. Eline run PT to find fluid level
22. RU N2 or use gas lift and push fluid below perfs (verify fluid depth with PT tool)
23. PU 4-1/2” CIBP/WRBP or patch
Note: All proposed perforations are in the same Pool / PA. A CIBP may be used instead of WRP if it is
determined that no cement is needed for operational purposes.
If necessary to cleanout or unload well with coiled tubing,
24. MIRU Fox Coiled Tubing Unit, PT BOPE to 3,500 psi High/250 psi Low
25. Provide AOGCC 24hrs notice of BOP test
26. PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth
27. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen
a. Reverse circ out any fluid if perfs are isolated/plugged back
28. RDMO coil tubing
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Fox CT BOP Drawing
4. Nitrogen procedure
See additional proposed perf intervals listed on updated Proposed wellbore diagram. -bjm
Updated by DMA 11-27-23
CURRENT SCHEMATIC
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,358’
TD = 7,703’ MD / TVD = 7,435’
RKB = 19.14’
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 L-80 TXP/BTC 3.958”3,090’7,701’
4-1/2"Prod Tieback 12.6 L-80 TXP/BTC 3.958”Surf 3,123’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 3,123’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Typle I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
TOC @ TOL (Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (lost returns at 250
bbls – rotated and recovered flow) pumped 37 bbls of 15.3 ppg Type I II tail). Circed
out 34bbls of spacer and 50 bbls of cmt/mud on returns.
8-1/2”
hole
RA 5588’
RA 6602
Updated by DMA 11-27-23
PROPOSED
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,358’
TD = 7,703’ MD / TVD = 7,435’
RKB to GL = 18.0’
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 TXP/BTC 3.958”3,090’7,701’7,701’
4-1/2"Prod Tieback 12.6 TXP/BTC 3.958”Surf 3,123’3,123’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 3,123’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Typle I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
TOC @ TOL (Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (lost returns at 250
bbls – rotated and recovered flow) pumped 37 bbls of 15.3 ppg Type I II tail). Circed
out 34bbls of spacer and 50 bbls of cmt/mud on returns.
8-1/2”
hole
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
TY_61-0 ±6,636'±6,645'±6,313'±6,322'±9'Proposed TBD
TY_61-8 ±6,748'±6,780'±6,418'±6,450'±32'Proposed TBD
TY_62-3 ±6,868'±6,895'±6,531'±6,558'±27'Proposed TBD
TY_62-5 ±6,977'±7,013'±6,633'±6,669'±36'Proposed TBD
TY_64-5 ±7,233'±7,251'±6,876'±6,894'±18'Proposed TBD
TY_67-0 ±7,446'±7,469'±7,079'±7,103'±24'Proposed TBD
TY_68-0 ±7,551'±7,570'±7,180'±7,199'±19'Proposed TBD
TY
RA 6602
RA 5588’
Superseded -bjm
Updated by CAH 12-4-23
PROPOSED
Swanson River Unit
SRU 232-15
PTD: 50-133-20714-00-00
API: 223-091
PBTD = 7,618’ MD / TVD = 7,358’
TD = 7,703’ MD / TVD = 7,435’
RKB to GL = 18.0’
Notes:
RA Tags @ 5588’ & 6602
Short joints (20ft) @ 6105’ & 7121’
CASING DETAIL
Size Type Wt Grade Conn.ID Top Btm
16”Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120'
9-5/8"Surf Csg 47 L-80 TXP 8.681”Surf 3,318’
4-1/2"Prod Lnr 12.6 TXP/BTC 3.958”3,090’7,701’7,701’
4-1/2"Prod Tieback 12.6 TXP/BTC 3.958”Surf 3,123’3,123’
1
16”
9-5/8”
12-1/4”
hole
4-1/2”
JEWELRY DETAIL
No.Depth ID OD Item
1 3,123’3.958”6.370”Bullet seal assembly in Baker SLZXP Liner top hanger
and Packer
OPEN HOLE / CEMENT DETAIL
9-5/8"TOC @ Surface (Pumped 259 bbls (565 sx) of 12 ppg Type I lead & 52 bbls (255sx) of
15.8 ppg type I tail cement. 60.7 bbls of lead returned.)
4-1/2”
TOC @ TOL (Pumped 312 bbls (718sx) of 12 ppg Type I lead cmt (casing packed off @
250 bbls – rotated and recovered flow) pumped 37 bbls of 15.3 ppg Type I II tail).
Circed out 34bbls of spacer and 50 bbls of cmt/mud on returns. CBL 12/2/23 -TOC @
3102’.
8-1/2”
hole
PERFORATION DETAIL
Sands Top
MD Btm MD Top TVD Btm TVD FT Date Status
TY_54-4 ±6,132’±6,147’±5,839’±5,853’±15 Proposed TBD
TY_55-7 ±6,345’±6,355’±6,040’±6,049’±10 Proposed TBD
TY_61-0 ±6,636'±6,645'±6,313'±6,322'±9'Proposed TBD
TY_61-0 ±6,577’±6,588’±6,258’±6,268’±11 Proposed TBD
TY_61-8 ±6,748'±6,780'±6,418'±6,450'±32'Proposed TBD
TY_62-3 ±6,868'±6,895'±6,531'±6,558'±27'Proposed TBD
TY_62-5 ±6,977'±7,013'±6,633'±6,669'±36'Proposed TBD
TY_64-5 ±7,233'±7,251'±6,876'±6,894'±18'Proposed TBD
TY_67-0 ±7,485’±7,494’±6,258’±6,268’9 Proposed TBD
TY_67-0 ±7,446'±7,469'±7,079'±7,103'±24'Proposed TBD
TY_68-0 ±7,551'±7,570'±7,180'±7,199'±19'Proposed TBD
TY
RA 6602
RA 5588’
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
Dewhurst, Andrew D (OGC)
From:Chad Helgeson <chelgeson@hilcorp.com>
Sent:Tuesday, December 5, 2023 13:03
To:Dewhurst, Andrew D (OGC)
Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Donna Ambruz; Guhl, Meredith D (OGC); Sean Wagner
Subject:RE: [EXTERNAL] RE: SRU 232-15 (PTD# 223-091) Sundry # 323-644 Additional perfs
Attachments:SRU 232-15 RT FE.las; SRU232-15_tops.xlsx; SRU 232-15 Surveys.csv
Follow Up Flag:Follow up
Flag Status:Flagged
Andrew,
PleaseĮndaƩachedrequestedinformaƟon.Letmeknowifyouneedanythingelse.
ChadHelgeson
From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>
Sent:Monday,December4,20235:06PM
To:ChadHelgeson<chelgeson@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Donna
Ambruz<dambruz@hilcorp.com>;Guhl,MeredithD(OGC)<meredith.guhl@alaska.gov>
Subject:[EXTERNAL]RE:SRU232Ͳ15(PTD#223Ͳ091)Sundry#323Ͳ644Additionalperfs
Chad,
IamassisƟngBryanreviewthissundry.Wouldyoupleaseprovidepreliminary,ĮeldͲqualitycopiesofthewelllogs(in.las
format),thedirecƟonalsurvey(inspreadsheetorASCIIͲtableformat),andyourpreliminarypicksforgeological
formaƟontopsforthiswell?
PleasenotethatthisĮeldͲqualityinformaƟondoesnotmeettheĮnalwellreporƟngrequirementsof20AAC25.071.
Thanks,
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservaƟonCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1254
From:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>
Sent:Monday,December4,202315:25
To:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>
Subject:FW:SRU232Ͳ15(PTD#223Ͳ091)Sundry#323Ͳ644Additionalperfs
Guys,
ThisoneisarushrequestfromHilcorp.Whenyouarereviewingthesundry,takenoteoftheupdatedperfdepthsinthe
aƩacheddiagram.
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
2
BryanMcLellan
SeniorPetroleumEngineer
AlaskaOil&GasConservationCommission
Bryan.mclellan@alaska.gov
+1(907)250Ͳ9193
From:ChadHelgeson<chelgeson@hilcorp.com>
Sent:Monday,December4,202310:56AM
To:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>
Cc:DonnaAmbruz<dambruz@hilcorp.com>
Subject:SRU232Ͳ15(PTD#223Ͳ091)Sundry#323Ͳ644Additionalperfs
Bryan,
AƩachedisanupdatedschemaƟcforsomeaddiƟonalperfsonSRU232Ͳ15.Ifyouhaven’tĮnalizedthesundryforthis
projectandcanaddthisschemaƟcitwouldbegreat.
OurgeologistworkingthisprojectleŌthecompanyandwegotanewGeooverseeingthisprojectandwantedtoadda
couplemoreintervalsinthiswellfromwhatwassubmiƩedlastweek.
ThesezonesareallwithintheTyonekPool.
LetmeknowifyouhaveanyquesƟonsorneedaddiƟonalinformaƟon.
ChadHelgeson
OperationsEngineer
KenaiAssetTeam
907Ͳ777Ͳ8405ͲO
907Ͳ229Ͳ4824ͲC
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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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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STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________SWANSON RIV UNIT 232-15
JBR 01/12/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:2
Tested with 4.5" test joint.
High PSI test on manual kill, upper pipe ram, choke valves 4, 5, 6 and floor safety valve failed.. Couldn’t initially determine which
valve was leaking by or if it was air in the system. Greased and functioned all associated valves, next low test attempt failed.
Bled off and fixed a leaking test manifold valve. Purged the stack, safety valve/ test joint, and choke manifold again and got a
solid low and high test. I believe it was air in the system from the amount of air that was pushed out, and no definitive leak
found.
Low PSI test on blind rams failed, bled pressure off and functioned rams several times, low test failed again. They then
loosened the tesion on the 4-way chains and functioned the rams a few more times and got a solid low and high PSI test.
Precharge bottles- 15 @ 1036 PSI.
Test Results
TEST DATA
Rig Rep:Shawn Trick / Ken PortOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson /J.Gruenber
Rig Owner/Rig No.:Hilcorp 169 PTD#:2230910 DATE:11/16/2023
Type Operation:DRILL Annular:
250/2500Type Test:INIT
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopJDH231115205037
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 11
MASP:
3086
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
15 FPNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11" 5M P
#1 Rams 1 2-7/8x5" VBR P
#2 Rams 1 Blinds FP
#3 Rams 1 2-7/8"x5" VB P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 2-1/16", 3-1/8 P
Kill Line Valves 2 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1650
200 PSI Attained P20
Full Pressure Attained P90
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2475
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P11
#1 Rams P5
#2 Rams P5
#3 Rams P5
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
99
9 9999
9
9
9FP
FP
floor safety valve failed.
blind rams failed,
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________SWANSON RIV UNIT 232-15
JBR 01/12/2024
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:The test was performed with 4.5" drill pipe.
15 Precharrge bottles with an average of 1036 PSI.
4 total gas and H2S stations, All tested well.
Very good test, they were very well prepared before I arrived.
TEST DATA
Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley
Contractor/Rig No.:Hilcorp 169 PTD#:2230910 DATE:11/11/2023
Well Class:DEV Inspection No:divJDH231111120235
Inspector Josh Hunt
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:16 P
Vent Line(s) Size:16 P
Vent Line(s) Length:113 P
Closest Ignition Source:105 P
Outlet from Rig Substructure:102 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:21 P
Knife Valve Open Time:3 P
Diverter Misc:0 NA
Systems Pressure:P3050
Pressure After Closure:P1475
200 psi Recharge Time:P24
Full Recharge Time:P123
Nitrogen Bottles (Number of):P4
Avg. Pressure:P2500
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Swanson River Unit, Beluga/Tyonek Gas Pool, SRU 232-15
Hilcorp Alaska, LLC
Permit to Drill Number: 223-091
Surface Location: 2279' FNL, 868' FWL, Sec 15, T8N, R9W, SM, AK
Bottomhole Location: 1919' FNL, 2277' FEL, Sec 15, T8N, R9W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of October 2023.
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.10.20 11:44:20
-08'00'
20
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth:12. Field/Pool(s):
MD: 7,815'TVD: 7,435'
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): 334.8 15. Distance to Nearest Well Open
Surface: x-348718 y- 2479984 Zone-4 316.8 to Same Pool:1900' to SRU 224-10
16. Deviated wells:Kickoff depth: 218 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 22 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
12-1/4" 9-5/8" 47# L-80 TXP 3,335' Surface Surface 3,335' 3,186'
8-1/2" 4-1/2" 12.6# L-80 TXP 4,680' 3,135' 2,995' 7,815' 7,435'
Tieback 4-1/2" 12.6# L-80 TXP 3,135' Surface Surface 3,135' 2,995'
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
SRU 232-15
Swanson River Unit
Beluga Gas Pool
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 - 1700 ft3 / T - 205 ft3
3086
1852' FNL, 1825' FWL, Sec 15, T8N, R9W, SM, AK
1919' FNL, 2277' FEL, Sec 15, T8N, R9W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
2279' FNL, 868' FWL, Sec 15, T8N, R9W, SM, AK AKA028406 / AKA028384
4960
18. Casing Program:Top - Setting Depth - BottomSpecifications
3829
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 1363 ft3 / T - 276 ft3
LengthCasing
Conductor/Structural
Effect. Depth MD (ft):Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Drilling Manager
Monty Myers
11/12/2023
2277' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback Assy.
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 No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
9.29.2023Drilling Manager
09/29/23
Monty M
Myers
By Grace Christianson at 2:01 pm, Sep 29, 2023
50-133-20714-00-00
Submit FIT/LOT results to AOGCC within 48 hrs of performing test.
Downhole commingling of production not allowed without AOGCC order.
BOP test to 3500 psi. Annular preventer test to 2500 psi.
DSR-10/2/23
223-091
BJM 10/20/23 A.Dewhurst 03OCT23JLC 10/20/2023
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.10.20 11:45:05 -08'00'
10/20/23
10/20/23
RBDMS JSB 102323
SRU 232-15
Drilling Program
Swanson River Unit
Rev 0
September 20, 2023
SRU 232-15
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.....................................................................................................11
10.0 N/U 21-1/4” 2M Diverter .........................................................................................................12
11.0 Drill 12-1/4” Hole Section ........................................................................................................13
12.0 Run 9-5/8” Surface Casing ......................................................................................................15
13.0 Cement 9-5/8” Surface Casing.................................................................................................18
14.0 BOP N/U and Test....................................................................................................................21
15.0 Drill 8-1/2” Hole Section ..........................................................................................................22
16.0 Run 4-1/2” Production Liner ...................................................................................................24
17.0 Cement 4-1/2” Production Liner .............................................................................................27
18.0 4-1/2” Liner Tieback Polish Run .............................................................................................30
19.0 4-1/2” Tieback Run ..................................................................................................................30
20.0 RDMO......................................................................................................................................31
21.0 Diverter Schematic ..................................................................................................................32
22.0 BOP Schematic ........................................................................................................................33
23.0 Wellhead Schematic.................................................................................................................34
24.0 Anticipated Drilling Hazards ..................................................................................................35
25.0 Hilcorp Rig 169 Layout ...........................................................................................................37
26.0 FIT/LOT Procedure.................................................................................................................38
27.0 Choke Manifold Schematic......................................................................................................39
28.0 Casing Design Information......................................................................................................40
29.0 8-1/2” Hole Section MASP .......................................................................................................41
30.0 Spider Plot (Governmental Sections NAD83).........................................................................42
31.0 660’ Radius for SSSV...............................................................................................................43
32.0 Surface Plat (As-Staked NAD27 & NAD83)...........................................................................44
Page 2 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
1.0 Well Summary
Well SRU 232-15
Pad & Old Well Designation SRU 12-15 (TS 2-15 or 32-15)
Planned Completion Type 4-1/2”Production Liner w/Tieback
Target Reservoir(s)Beluga/Tyonek
Planned Well TD, MD / TVD 7815’MD / 7,435’ TVD
PBTD, MD 7715’ MD
AFE Number 231-00059
AFE Drilling Days 21
AFE Drilling Amount $4,495,000
Maximum Anticipated Pressure
(Surface)3086 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3829 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 335.3’(316.8 + 18.5)
Ground Elevation 316.8’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
2.0 Management of Change Information
Page 4 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”17”84 J-55 Weld 2980 1410 -
12-1/4”9.625”8.681”8.525”10.625”47 L-80 TXP 6870 4750 1086
Prod
8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 TXP 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
Page 5 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
x Report covers operations from 6am to 6am
x 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 work day to mmyers@hilcorp.com,
sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage.
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. John Coston: O: (907) 777-6726 C: (907) 227-3189
2. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
3. For Spills:
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com, and cdinger@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
Page 6 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
6.0 Planned Wellbore Schematic
Page 7 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
7.0 Drilling / Completion Summary
SRU 232-15 is an S-shaped directional grassroots development well to be drilled from SRU 12-15 Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Sterling and Beluga sands.
The base plan is a directional wellbore with a kickoff point at ~200’MD. Maximum hole angle will be 22
deg. and TD of the well will be 7815’ TMD/ 7,435’ TVD, ending with 19 deg inclination.
Drilling operations are expected to commence approximately December 2023. The Hilcorp Rig # 169 will be
used to drill the wellbore then run casing and cement.
9-5/8” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater
resources. Cement returns to surface will confirm TOC at surface.
All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 169 to well site
2. N/U diverter and test.
3. Drill 12-1/4”hole to 3,335’ MD. Run and cmt 9-5/8”surface casing.
4. ND diverter, N/U & test 11” x 5M BOP to 3500 psi
5. Test Surface casing to 3500 psi.
6. Drill out shoe and perform a FIT to 12.8 ppg EMW
7. Drill 8-1/2” hole section to 7,815’MD. Perform Wiper trip.
8. Run and cmt 4-1/2”production liner.
9. PU polish mill assembly and RIH to polish sealbore
10. Displace well above liner top to 6% KCL completion fluid.
11. POOH and LDDP.
12. RIH and land 4-1/2” tieback string in liner top.
13. MIT Tubing and IA to 3500 psi.
14. N/D BOP, N/U dry hole tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: GR + Res LWD
2. Production Hole: Triple Combo LWD
3. Mud loggers from surface casing point to TD.
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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 and all
BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how
to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling of SRU 232-15. Ensure to provide
AOGCC 24 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation, test all BOP components
utilized for well control prior to the next trip into the wellbore. This pressure test will be charted
same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man
office.
x Review all conditions of approval of the AOGCC PTD on the 10-401 form and the BLM APD.
Ensure that the conditions of approval are captured in shift handover notes until they are executed
and complied with.
Regulation Variance Requests:
x BLM:
o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to install a 2-1/16” 5M HCR
valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with
installation of a check valve in the kill line.
o Onshore Oil and Gas Order No. 2.IV: Hilcorp requests approval to utilize flexible choke and kill
lines in lieu of hard piping.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
8-1/2”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to testing BOPs.
x Any other notifications required in APD.
Required BLM Notifications:
x 48 hours before spud. Follow up with actual spud date and time within 24 hours.
x 72 hours before casing running and cmt operations
x 72 hours before BOPE tests
x 72 hours before logging, coring, & testing
x Any other notifications required in APD
Additional requirements may be stipulated on APD and Sundry.
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Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
BLM
Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127
Email: aschoessler@blm.gov
Use the below email address for BOP notifications to the BLM:
BLM_AK_AKSO_EnergySection_Notifications@blm.gov
2016 Waste Prevention Rule -
Waste Minimization Plan for Drilling:
Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced
from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility
for beneficial reuse, if possible after testing, and disposal.
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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 Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line
up with flowline later.
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 RU Mud loggers on surface hole section for gas detection only. No samples required
9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.9 Mix mud for 12-1/4”hole section.
9.10 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.
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10.5 Rig 169 and estimated Diverter line orientation on SRU 12-15 Pad:
11.0 Drill 12-1/4”Hole Section
11.1 P/U 12-1/4”directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2”Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 12-1/4”hole section to 3,335’MD/ 3,186’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Kenai and Inlet experience to drill through coal seams efficiently.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise.
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x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x Take MWD surveys every stand drilled (60’ intervals).
11.5 12-1/4”hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-3,335’ 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 9-5/8”Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8”casing running equipment.
x Ensure 9-5/8”TXP x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 9-5/8”surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values
required to achieve this position.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top 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.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 9-5/8”Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x Discuss how to handle cmt returns at surface.
x Confirm which pump will be utilized for displacement, and how fluid will be fed to
displacement pump.
x Determine 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 + 50% open hole excess. Job will consist of lead &
tail, TOC brought to surface.
Estimated Total Cement Volume:
Verified cement calcs -bjm
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Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Displacement calculation:
3336’- 100’ = 3236’x .07321 bpf = 237 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar.
13.13 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 7.3 bbls.
13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
Lead Slurry (2836’ MD to surface)Tail Slurry (3336’ to 2836’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.40 ft3/sk 1.16 ft3/sk
Mixed Water 14.25 gal/sk 5.04 gal/sk
Mixed Fluid 14.25 gal/sk 5.04 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
Halad-344 Fluid Loss Halad-344 Fluid Loss
CalSeal Accelerator CalSeal Accelerator
VersaSet Thixotropic CFR-3 Dispersant
D-Air 5000 Anti Foam UCS Slurry Conditioner
Econolite Light-weight add.Super CBL Anti-Gas Migration
SA-1015 Suspension Agent
BridgeMaker II Lost Circulation
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13.15 R/D cement equipment. Flush out wellhead with FW.
13.16 Back out and L/D landing joint. Flush out wellhead with FW.
13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.18 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com.
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14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U multi-bowl wellhead assy. Install 9-5/8” packoff P-seals. Test 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
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Run 4-1/2”BOP test assy, land out test plug (if not installed previously).
x Utilize 4-1/2” test joint.
x Test BOP to 250/3500 psi for 5/10 min. Test annular to 250/2500 psi for 5/10 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.2 ppg 6% KCL PHPA mud system.Plan ahead to TD with 10.2 ppg mud.
14.8 R/U mud loggers for production hole section.
14.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 8-1/2” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH, Conduct shallow hole test of MWD and confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
Starting mud weight for the production interval is 9.2ppg or the surface interval mud weight at
TD, whichever is heavier.
Weighting material to be used for the hole section will be barite, salt and calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg above
highest anticipated MW.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 9.2 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
3336’- 7815’9.0 –10.5 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 –10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.9-5/8” burst is 6870 psi / 2 = 3435 psi.
15.11 Drill out shoe track and 20’ of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 12.8 ppg EMW. (12.4 FIT = 18 bbl KTV)
15.14 Drill 8-1/2” hole section to 7815’ MD / 7435’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x On the second wiper trip (around 5,300’ MD), trip back to the 9-5/8” shoe to split the hole
section in half
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed
necessary.
x Take (3) sets of formation samples every 20’.
x 10.2 ppg mud required below 7100’ TVD.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8”shoe. Be aware, on the most
recent well drilled on TS 2-15 Pad (SRU 224-10), mud weight had to be increased after the wiper
trip to 10.2 ppg.
15.16 TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run
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15.17 POOH LDDP and BHA.
15.18 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
16.0 Run 4-1/2”Production Liner
16.1. R/U Parker 4-1/2”casing running equipment.
x Ensure 4-1/2”TXP 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:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 4-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 9-5/8” shoe. Leave the centralizers free
floating.
x 2 Joints with RA tags will be placed to better identify the Beluga for post-rig work. Geo and
Ops engineer will communicate the depths for these joints.
16.5. Continue running 4-1/2” production liner
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16.6. Run in hole w/ 4-1/2” liner to the 9-5/8” casing shoe.
16.7. Fill the 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 4-1/2” X 9-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner
volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque
parameters of the liner.
16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust
slower as hole conditions dictate.
16.14. 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.
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17.0 Cement 4-1/2”Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Verified cement calcs -bjm
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Cement Slurry Design:
17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow –continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 1 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
Lead Slurry (7315’ MD to 3136’ MD)Tail Slurry (7815’ to 7315’ MD)
System Extended Conventional
Density 12 lb/gal 15.4 lb/gal
Yield 2.46 ft3/sk 1.22 ft3/sk
Mixed Water 14.349 gal/sk 5.507 gal/sk
Mixed Fluid 14.469 gal/sk 5.507 gal/sk
Additives
Code Description Concentration Code Description Concentration
G Cement 94#/sk A Cement 94#/sk
D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC
D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC
D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC
D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC
Page 29 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
Backup release from liner hanger:
17.21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will
have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure
and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear
screws.
17.22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then
proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop
1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up
with workstring to release collet from the profile.
17.24. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes.
Page 30 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com.
18.0 4-1/2”Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. CBU and displace well to 6% KCl completion fluid.
18.4. POOH LDDP and BHA
18.5. If not completed, test 4-1/2” liner to 3,500 psi and chart for 30 minutes
19.0 4-1/2” Tieback Run
19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 TXP tubing.
x No SSSV, GLM, or CIM 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 PU hanger and land string in hanger bowl. Note distance of seals from no-go.
Page 31 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
19.4 Install packoff and test hanger void.
19.5 Test 4-1/2” liner and tieback to 3,500 psi and chart for 30 minutes.
19.6 Test 9-5/8” x 4-1/2” annulus to 3,500 psi and chart for 30 minutes.
20.0 RDMO
20.1. Install BPV in wellhead
20.2. N/D BOPE
20.3. N/U dry hole tree or full tree (if available).
20.4. RDMO Hilcorp Rig #169
Page 32 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
21.0 Diverter Schematic
Page 33 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
22.0 BOP Schematic
Page 34 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
23.0 Wellhead Schematic
Page 35 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
24.0 Anticipated Drilling Hazards
9-7/8”Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 –45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
-A.Dewhurst 03OCT2312-1/4"
Page 36 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Losses not experienced in SRU 241-33B in 2021. However, ensure all LCM inventory is fully stocked
before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
Reservoir Pressure:
9.9 ppg pore pressure expected at TD
8-1/2"
Page 37 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
25.0 Hilcorp Rig 169 Layout
Page 38 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
26.0 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 39 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
27.0 Choke Manifold Schematic
Page 40 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
28.0 Casing Design Information
Page 41 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
29.0 8-1/2” Hole Section MASP
Page 42 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
30.0 Spider Plot (Governmental Sections NAD83)
Page 43 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
31.0 660’ Radius for SSSV
Page 44 Version 0 September, 2023
SRU 232-15
Drilling Procedure
Rev 0
32.0 Surface Plat (As-Staked NAD27 & NAD83)
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Vertical Section at 81.50° (1000 usft/in)
SRU 232-15 wp06 tgt1
SRU 232-15 wp06 tgt2
16" Casing
9 5/8"_Casing
4 1/2" Casing
5 00
100 0
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7 8 1 5 SRU 232-15 wp06
Start Dir 1.5º/100' : 218' MD, 218'TVD
Start Dir 2.5º/100' : 1018' MD, 1012.16'TVD
End Dir : 1478.82' MD, 1452.25' TVD
Start Dir 2.5º/100' : 2467.87' MD, 2367.5'TVD
End Dir : 3041.74' MD, 2907.96' TVD
Total Depth : 7815.26' MD, 7434.8' TVD
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: Swanson River Unit 232-15
316.80
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2479984.10 348718.60 60° 47' 7.5041 N 150° 50' 47.6456 W
SURVEY PROGRAM
Date: 2023-09-20T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.00 1000.00 SRU 232-15 wp06 (SRU 232-15) 3_Gyro-GC_Drill pipe
1000.00 3335.00 SRU 232-15 wp06 (SRU 232-15) 3_MWD+IFR1+MS+Sag
3335.00 7814.42 SRU 232-15 wp06 (SRU 232-15) 3_MWD+IFR1+MS+Sag
FORMATION TOP DETAILS
No formation data is available
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Swanson River Unit 232-15, True North
Vertical (TVD) Reference:RKB - As-Staked @ 334.80usft (HEC 169)
Measured Depth Reference:RKB - As-Staked @ 334.80usft (HEC 169)
Calculation Method:Minimum Curvature
Project:Swanson River Unit
Site:SRF TS 2-15 Pad
Well:Swanson River Unit 232-15
Wellbore:SRU 232-15
Design:SRU 232-15 wp06
CASING DETAILS
TVD TVDSS MD Size Name
120.00 -214.80 120.00 16 16" Casing
3186.00 2851.20 3334.93 9-5/8 9 5/8"_Casing
7434.80 7100.00 7815.26 3-1/2 4 1/2" Casing
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
2 218.00 0.00 0.00 218.00 0.00 0.00 0.00 0.00 0.00 Start Dir 1.5º/100' : 218' MD, 218'TVD
3 1018.00 12.00 34.00 1012.16 69.20 46.68 1.50 34.00 56.39 Start Dir 2.5º/100' : 1018' MD, 1012.16'TVD
4 1478.82 22.27 52.60 1452.25 162.27 143.17 2.50 37.25 165.58 End Dir : 1478.82' MD, 1452.25' TVD
5 2467.87 22.27 52.60 2367.50 389.95 440.97 0.00 0.00 493.77 Start Dir 2.5º/100' : 2467.87' MD, 2367.5'TVD
6 3041.74 18.50 93.25 2907.96 451.17 619.20 2.50 123.47 679.08 SRU 232-15 wp06 tgt1 End Dir : 3041.74' MD, 2907.96' TVD
7 7492.59 18.50 93.25 7128.80 371.10 2029.20 0.00 0.00 2061.76 SRU 232-15 wp06 tgt2
8 7815.26 18.50 93.25 7434.80 365.30 2131.42 0.00 0.00 2162.01
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
X
223-091
SWANSON RIVER
TYONEK GAS POOL, BELUGA GAS POOL
Swanson River Unit 232-15
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t
c
a
n
b
e
i
s
s
u
e
d
w
i
t
h
o
u
t
c
o
n
s
e
r
v
a
t
i
o
n
o
r
d
e
r
Ye
s
12
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
i
t
h
o
u
t
a
d
m
i
n
i
s
t
r
a
t
i
v
e
a
p
p
r
o
v
a
l
Ye
s
13
C
a
n
p
e
r
m
i
t
b
e
a
p
p
r
o
v
e
d
b
e
f
o
r
e
1
5
-
d
a
y
w
a
i
t
NA
14
W
e
l
l
l
o
c
a
t
e
d
w
i
t
h
i
n
a
r
e
a
a
n
d
s
t
r
a
t
a
a
u
t
h
o
r
i
z
e
d
b
y
I
n
j
e
c
t
i
o
n
O
r
d
e
r
#
(
p
u
t
I
O
#
i
n
c
o
m
m
e
n
t
s
)
(
F
o
r
s
e
r
v
NA
15
A
l
l
w
e
l
l
s
w
i
t
h
i
n
1
/
4
m
i
l
e
a
r
e
a
o
f
r
e
v
i
e
w
i
d
e
n
t
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
NA
16
P
r
e
-
p
r
o
d
u
c
e
d
i
n
j
e
c
t
o
r
:
d
u
r
a
t
i
o
n
o
f
p
r
e
-
p
r
o
d
u
c
t
i
o
n
l
e
s
s
t
h
a
n
3
m
o
n
t
h
s
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
NA
17
N
o
n
c
o
n
v
e
n
.
g
a
s
c
o
n
f
o
r
m
s
t
o
A
S
3
1
.
0
5
.
0
3
0
(
j
.
1
.
A
)
,
(
j
.
2
.
A
-
D
)
Ye
s
18
C
o
n
d
u
c
t
o
r
s
t
r
i
n
g
p
r
o
v
i
d
e
d
Ye
s
19
S
u
r
f
a
c
e
c
a
s
i
n
g
p
r
o
t
e
c
t
s
a
l
l
k
n
o
w
n
U
S
D
W
s
Ye
s
20
C
M
T
v
o
l
a
d
e
q
u
a
t
e
t
o
c
i
r
c
u
l
a
t
e
o
n
c
o
n
d
u
c
t
o
r
&
s
u
r
f
c
s
g
Ye
s
21
C
M
T
v
o
l
a
d
e
q
u
a
t
e
t
o
t
i
e
-
i
n
l
o
n
g
s
t
r
i
n
g
t
o
s
u
r
f
c
s
g
Ye
s
22
C
M
T
w
i
l
l
c
o
v
e
r
a
l
l
k
n
o
w
n
p
r
o
d
u
c
t
i
v
e
h
o
r
i
z
o
n
s
Ye
s
23
C
a
s
i
n
g
d
e
s
i
g
n
s
a
d
e
q
u
a
t
e
f
o
r
C
,
T
,
B
&
p
e
r
m
a
f
r
o
s
t
Ye
s
24
A
d
e
q
u
a
t
e
t
a
n
k
a
g
e
o
r
r
e
s
e
r
v
e
p
i
t
NA
25
I
f
a
r
e
-
d
r
i
l
l
,
h
a
s
a
1
0
-
4
0
3
f
o
r
a
b
a
n
d
o
n
m
e
n
t
b
e
e
n
a
p
p
r
o
v
e
d
Ye
s
26
A
d
e
q
u
a
t
e
w
e
l
l
b
o
r
e
s
e
p
a
r
a
t
i
o
n
p
r
o
p
o
s
e
d
Ye
s
27
I
f
d
i
v
e
r
t
e
r
r
e
q
u
i
r
e
d
,
d
o
e
s
i
t
m
e
e
t
r
e
g
u
l
a
t
i
o
n
s
Ye
s
28
D
r
i
l
l
i
n
g
f
l
u
i
d
p
r
o
g
r
a
m
s
c
h
e
m
a
t
i
c
&
e
q
u
i
p
l
i
s
t
a
d
e
q
u
a
t
e
Ye
s
29
B
O
P
E
s
,
d
o
t
h
e
y
m
e
e
t
r
e
g
u
l
a
t
i
o
n
Ye
s
M
P
S
P
=
3
0
5
0
p
s
i
,
B
O
P
r
a
t
e
d
t
o
5
0
0
0
p
s
i
(
B
O
P
t
e
s
t
t
o
3
50
0
p
s
i
)
30
B
O
P
E
p
r
e
s
s
r
a
t
i
n
g
a
p
p
r
o
p
r
i
a
t
e
;
t
e
s
t
t
o
(
p
u
t
p
s
i
g
i
n
c
o
m
m
e
n
t
s
)
Ye
s
31
C
h
o
k
e
m
a
n
i
f
o
l
d
c
o
m
p
l
i
e
s
w
/
A
P
I
R
P
-
5
3
(
M
a
y
8
4
)
Ye
s
32
W
o
r
k
w
i
l
l
o
c
c
u
r
w
i
t
h
o
u
t
o
p
e
r
a
t
i
o
n
s
h
u
t
d
o
w
n
No
33
I
s
p
r
e
s
e
n
c
e
o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
Ye
s
34
M
e
c
h
a
n
i
c
a
l
c
o
n
d
i
t
i
o
n
o
f
w
e
l
l
s
w
i
t
h
i
n
A
O
R
v
e
r
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
Ye
s
H
2
S
n
o
t
a
n
t
i
c
i
p
a
t
e
d
35
P
e
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
M
a
x
p
o
r
e
p
r
e
s
s
u
r
e
o
f
9
.
9
p
p
g
E
M
W
e
x
p
e
c
t
e
d
a
t
T
D
36
D
a
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
S
e
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
S
e
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
C
o
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
AD
D
Da
t
e
10
/
3
/
2
0
2
3
Ap
p
r
BJ
M
Da
t
e
10
/
2
0
/
2
0
2
3
Ap
p
r
AD
D
Da
t
e
10
/
3
/
2
0
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
JL
C
1
0
/
2
0
/
2
0
2
3
