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Alaska Oil and Gas Conservation Commission
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 9/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240927
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF
BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF
BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf
BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf
BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL
END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey
KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF
MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey
MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey
MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut
MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut
MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug
NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf
NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL
NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF
NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog
PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch
PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL
PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF
PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL
PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL
PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF
Please include current contact information if different from above.
T39593
T39594
T39595
T39596
T39597
T39598
T39599
T39600
T39601
T39602
T39603
T39603
T39604
T39605
T39605
T39605
T39605
T39606
T39606
T39607
T39608
T39609
T39609
T39610
T39611
BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.27 14:47:28 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 9/9/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240909
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 24 50133206390000 214112 8/22/2024 AK E-LINE PPROF
BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf
BRU 241-34S 50283201980000 224077 8/9/2024 AK E-LINE PPROF
KBU 32-06 50133206580000 216137 8/17/2024 AK E-LINE PPROF
KBU 32-06 50133206580000 216137 7/20/2024 AK E-LINE PPROF
MPU L-54 50029236070000 218066 8/14/2024 READ Caliper Survey
Please include current contact information if different from above.
T39522
T39523
T39524
T39525
T39525
T39526
BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.09.09 12:37:48 -08'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Beluga River Field
GL: 79.4' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" L-80 120'
7-5/8" P-110 2,633'
3-1/2" L-80 6,900'
3-1/2" L-80 2,478'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
01309 0
8/19/2024 24
Flow Tubing
1
1344
N/A13440
2472' FNL, 2480' FWL, Sec 26, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9.3#
2,914'
2,446'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
7/13/2024
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
320276
320452
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
Conductor
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2627731
SETTING DEPTH TVD
2627923
TOP HOLE SIZE
CBL 7-1-24, Mudlogs, LWD (DGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs
N/A
N/A
N/A
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
318704 2625965
50-283-20195-00-00June 10, 2024
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
7/12/2024 224-035 / 324-364
N/A
BRU 222-26June 18, 2024815' FSL, 765' FWL, Sec 26, T13N, R10W, SM, AK
97.9'
Sterling - Beluga Gas Pool
AKA029657
7,654' MD / 6,901' TVD
7,619' MD / 6,867' TVD
2613' FSL, 2306' FWL, Sec 26, T13N, R10W, SM, AK
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy.Tieback
TUBING RECORD
L - 451 sx / T - 122 sx6-3/4"
9-7/8"
Driven
Surface L - 438 sx / T - 174 sx
9.2#
Surface
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,873' 7,653'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Surface
3,111'
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 James Brooks at 12:00 pm, Aug 29, 2024
Completed
7/12/2024
JSB
RBDMS JSB 090524
GBJM 1/27/25 DSR-10/14/24SFD 3/27/2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel F2 5062' 4,329'
3997' 3330'
4406' 3685'
4636' 3902'
5009' 4270'
5488' 4746'
5836' 5093'
6562' 5815'
7114' 6365'
7463' 6711'
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:
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
INSTRUCTIONS
Bel J5
Bel F
ST B1
Bel G
Bel J
Bel D
Bel E
Bel H
Bel I
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
08/29/24
Monty M
Myers
Updated by CJD 08-28-24
CURRENT SCHEMATIC
Beluga River Unit
BRU 222-26
PTD: 224-035
API: 50-283-20195-00-00
PBTD = 7,619’ / TVD = 6,876’
TD = 7,654’ / TVD = 6,901’
RKB to GL = 19.85’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 P-110 GB-CD 6.875” Surf 3,111’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,873’ 7,652’
3-1/2" Prod Tieback 9.3 L-80 8RD EUE 2.992” Surf 2,903’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,566’ 2.813” 3.500” Chemical Injection Sub
2 2,873’ 4” 6.540” Ranger Liner Hanger w/ Scout liner to packer
3 2,903’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" Pumped 188 bbls (438sks) of 12ppg lead with 33 bbls (174 sks) of 15.8ppg tail and
bumped plug. 95 bbls of cement returns to surface.
3-1/2” Pumped 185 bbls of 12 ppg lead and 24 bbls of 15.3 ppg tail, bumped plug. 9 bbls of
losses with 59 bbls of cement returns. CBL run 7/1/24 show TOC @ 2950’ or TOL.
6-3/4”
hole
2
1
Notes:
Fish
2.75” CIBP w/tool string (lost 7/22/24) tagged @ 6205’ 8/15/24
2.23” LIB w/ 1.75” x 22ft long tool string (Lost 7/22/24 @ 5939’)
2.77 GR & JB 4ft long (Lost 7/22/24 @ 6185’)
2.5” CIBP w/ tool string (lost 7/21/24 @ 6185’)
Short
Joints Approx 15ft joints @ 3600, 4115, 4597, 5113, 5628, 6113, 6629, & 7144ft
PERFORATION DETAIL
Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments
Pool Top Sterling A1 - 3,764’ MD / 3,143’ TVD
Beluga F2 5,062’ 5,067’ 4,323’ 4,328’ 5’ 8/20/24 Open
Beluga F2 5,082’ 5,092’ 4,343’ 4,353’ 10’ 8/20/24 Open
Beluga F2 5,117’ 5,120’ 4,378’ 4,381’ 3’ 8/20/24 Open
Beluga F5 5,141’ 5,146’ 4,402’ 4,407’ 5’ 8/20/24 Open
Beluga F5 5,150’ 5,156’ 4,411’ 4,417’ 6’ 8/20/24 Open
Beluga F6 5,188’ 5,191’ 4,448’ 4,451’ 3’ 8/19/24 Open
Beluga F6 5,216’ 5,222’ 4,476’ 4,482’ 6’ 8/19/24 Open
Beluga F7 5,270’ 5,274’ 4,530’ 4,534’ 4’ 8/19/24 Open
Beluga F7 5,340’ 5,344’ 4,600’ 4,604’ 4' 8/19/24 Open
Beluga F7 5,366’ 5,372’ 4,626’ 4,632’ 6’ 8/16/24 Open
Beluga F10 5,414’ 5,419’ 4,673’ 4,678’ 5’ 8/15/24 Open
Beluga F10 5,438’ 5,443’ 4,697’ 4,702’ 5’ 8/15/24 Open
Beluga G1 5,521’ 5,533’ 4,779’ 4,791' 12’ 8/15/24 Open
Beluga G2 5,549’ 5,554’ 4,807' 4,812' 20' 8/7/24 Open
Beluga G2 5,554’ 5,574’ 4,812' 4,832' 20' 7/17/24 Open
Beluga G3 5,585’ 5,591’ 4,843' 4,849' 6' 7/17/24 Open
Beluga G3 5,612’ 5,618’ 4,870' 4,876' 6' 7/17/24 Open
Beluga G4 5,641’ 5,648’ 4,899' 4,906' 6' 7/16/24 Open
Beluga G4 5,682’ 5,687’ 4,940' 4,945' 5' 7/16/24 Open
Beluga G6 5,700’ 5,708’ 4,958' 4,966' 8' 7/16/24 Open
Beluga G9 5,776’ 5,781’ 5,033' 5,038' 5' 7/16/24 Open
Beluga H 5,849’ 5,856’ 5,106' 5,113' 6' 7/16/24 Open
Beluga H2 5,923’ 5,937’ 5,180' 5,194' 14' 7/16/24 Open
Beluga H3 5,974’ 5,980’ 5,230' 5,236' 6' 7/16/24 Open
Beluga H4 6,000’ 6,006’ 5,256' 5,262' 6' 7/16/24 Open
Beluga H7 6,123’ 6,131’ 5,379' 5,387' 8' 7/13/24 Open
Beluga H8 6,150’ 6,187’ 5,405' 5,442' 38' 7/13/24 Open
Beluga H10 6,250’ 6,262’ 5,505' 5,517' 12' 7/13/24 Open
Beluga H10 6,269’ 6,275’ 5,524' 5,530' 6' 7/13/24 Open
Beluga H11 6,295’ 6,312’ 5,550' 5,567' 17' 7/13/24 Open
Page 1/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:6/5/2024 End Date:6/25/2024
Report Number
1
Report Start Date
6/5/2024
Report End Date
6/6/2024
Operation
Held PJSM, staged cranes, RU and removed derrick and carrier from sub, sub from pony walls and transported to H pad. Set pony walls and sub, centered up over
conductor, set carrier, drill line spool, derrick and iron roughneck.
Set doghouse and raised same, set pit 1 and jig, set pump skids, set pits 2 and 3 and raised roof tops, set pump room clam shell, set HPU skid. Set gen skid and service
shacks, layed out liner and rig mats for catwalk, set catwalk, folded over beaver slide. Set cuttings box, upright water tank a nd cement silo.
Hooked up electrical, air, water, and fuel lines between rig modules. Worked on running & plugging in Pason cables. Installed & plugged in roof top lights on modules.
rasied/installed handrails. Filled water upright tank & rig water tank. Got water circulating throughout the rig. Got rig lights turned on. Replaced water pump in green safety
shack. Installed equilizer lines between pit modules 1 & 2. R/U high pressure lines between MP's and jumper hoses between MP's and pits. Raised and R/U degasser in
pit #3.
Crew change, held PTSM. Cont. with R/U. Adjusted brake handle and linkage. Performed derrick inspection. Held PJSM, raised derr ick to half-mast. Removed old
centrifuge stand & feed pump off premix tank. Cont. R/U pit system. R/U air lines from carrier to doghouse. Currently spooling up drill line.
Report Number
2
Report Start Date
6/6/2024
Report End Date
6/7/2024
Operation
Installed turnbuckles on upper torque tube, pulled lower torque tube to rig floor and pinned to upper section, stood and pinned poorboy degasser with crane, set centrifuge
on stand with crane, installed fluid return line from MGS to shakers, removed motor from agitator in pit #8 for seal replacemen t, inspected derrick for scope up, held
PJSM, scoped up derrick and pinned.
Installed lower turnbuckles and T bar, staged topdrive for PU, un-bridled blocks and secured cables. Troubleshoot floor motor throttle control. HandyBerm Reps bermed in
rig and tank farm on D pad. Replaced agitator #2 gear box, cleaned rod wash tubs, staged casing tong power pack, racked test joints.
P/U and hung TDS on blocks and TQ bushing. Install Handy Berm around rig foot print and tank farm. M/U Kelley hose & service loop to TDS. Purged HYD lines.
Function tested robotics. Trouble shooting TDS extend. Working on hooking up Pason cables. R/U centrifuge & serviced. Replaced broken ball valves on water lines in pit
system. Organized & cleaned 40' conex, spill conex, and drilling conex. R/U Geronimo line.
Crew change, held PTSM. Cont. hooking up Pason cables and trouble shooting TDS extend. Removed shipping beams in sub base. Set up mud /misc. equip. docks.
Installed IBOP, saver-sub, and clamps. Re-wrapped Kelley hose & service loop to change hanging orentation of service loop. Checked koomey bottle pressures.
Changed out schrader valve in bottle #10 and charged wtih nitrogen.
Report Number
3
Report Start Date
6/7/2024
Report End Date
6/8/2024
Operation
Powered up service shacks, installed washpipe on topdrive, adjusted torque tube to center TD over hole, function tested topdriv e and dressed same, dressed rig floor, RU
comm’s to service shacks. Took on water in pit to test charge pumps etc.
Removed fiberglass grating from cellar box, met with welder on fabricating steel grating for cellar box and modify 8” dump line , installed gas sensors/alarms, set adaptor
flange, installed spacer spool/diverter "T", set annular. Gave BLM and AOGCC 72 hr notice for witness of diverter function test , BLM Rep Quinn Sawyer waived witnesss
via email at 13:24 on 6-7-24.
Bolt up annular, "T" and spacer spool to adaptor flange, knife valve, and vent line w/ anchors- Total lenght 112', and 92' to c losest ignition source. Hydro tested pit system,
bump tested centrifuge.
Crew change, held PTSM. Freed up rotary table locks. R/U bleeder & fill up lines on diverter stack. R/U koomey HYD lines to kni fe valve & annular on stack. Installed
stairs on catwalk. Worked on rig acceptance check list.
Medevac'd out CCI night rig support lead at 04:00 hrs. Due to having chest pains.
Report Number
4
Report Start Date
6/8/2024
Report End Date
6/9/2024
Operation
Function tested diverter, installed splash guard around flow riser under table, installed jumper hose from catwalk to poorboy d egasser, charged #2 pump pulsation
dampener, test ran liner wash and lube pumps, bump tested vac degasser, charge pumps. Tested pump throttles, pumped through bleeders and popoff’s, pressure tested
surface lines
Calibrated and tested gas alarms/lights, installed 4” valves on conductor outlets, 4 way chained off stack, installed grating o n cellar box, took on water in pits and started
mixing spud mud, work on topdrive/torquebushing teflon and shims and get topdrive hanging true/straight.
Cont. mixing spud mud. Re-shimmed TDS. Loaded out catwalk racks with 4.5" DP.
Installed rotary table mouse hole. Strapped & tallied DP.
Inspected rig floor handling equip. Charged compensators of TDS. Verified TQ against TDS, IR, and Tongs. P/U DP singles, built and racked back stds in the derrick.
Report Number
5
Report Start Date
6/9/2024
Report End Date
6/10/2024
Operation
Racked back total 51 stnds DP, 8 stnds HWDP, removed another shim from torque bushing to level up topdrive, cont mixing spud mud, installed Rig Smart sensors on
crown, derrick board, topdrive, bails and iron roughneck, welder built plug for 169 cuttings box dump line, GeoLog RU gas trap/monitoring system, took on rig fuel,
secured grating on cellar box.
Welder fabricated a turn to 147 dump line to clear leg of centrifuge stand, installed mount bracket in doghouse for rig gas ala rm control panel, welder installed extension
on shaker 2 cuttings chute, installed cameras for shakers and pump room, installed mast cylinder covers, installed bushings in extend arms, cont mixing spud mud, cont
install of Rig Smart system.
Secured cellar grating with clips. Cleaned & organized rig modules. Cleaned & inspected TDS for leaks. Finished building Spud m ud. Strapped & tallied 7-5/8" 29.7#
P-110 GB-CD BTC surface casing.
Crew change, Held PTSM and weekly safety meeting w/ rig crew. Cont. w/ housekeeping and inventories. R/U Hotsy and pressure washed rig. Added oil to TDS. Verify
hole center. Installed short mouse hole. Prepared all rig floor equip. to P/U BHA. Prepped remaining welding projects for welder.
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #:
State: ALASKA
Rig/Service: HEC 147Permit to Drill (PTD) #:224-035
Page 2/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Report Number
6
Report Start Date
6/10/2024
Report End Date
6/11/2024
Operation
Completed running cords for Rig Smart, cont working welding projects, brought in and staged mud product on docks, start working blocks for setting speed limits, high/low
height limits, bale angle for connections etc. Wait on welder to return with shaker parts for install, laid out and numbered su rface casing for PU.
Accepted rig at 12:00 on 6-10-24. Cont function testing and setting limits on Rig Smart system and training Driller on use, tes ted audio and visual gas alarms with no
issues. Parked stand of DP in hole in prep for diverter function test while welders install cuttings dump extension on edge of both shakers.
Function tested diverter system, performed koomey draw down test, took measurements on vent line and set signs/barriers for blo ckade of vent line, tested flow show and
PVT gain/loss audio and visual alarms.
Witness of testing was waived by BLM Rep Quinn Sawyer via email on 6-7-24 at 12:41 pm
Witness of testing was waived by AOGCC Rep Jim Regg via email on 6-9-24 at 16:51 pm.
With shaker welding projects done, flooded conductor with spud mud and checked for leaks (ok). P/U 1.5° degree motor, M/U 9-7/8" PDC 5 bladed bit. Measured off set=
187°. M/U MWD tools- DM, DGR, PWD, ADR, and TM. Plugged in an uploaded MWD data. Screwed in and performed shallow pulse test. Tagged bottom with bit @ 116'.
Held PJSM on Spudding. Spudded well @ 22:35 hrs.
Rotary drilled F/116'-T/212'. P/U-23K S/O-19K ROT-20K GPM-400 SPP-735 psi RPM-40 ROP-180 TQ-2.3K WOB-2K Diff-50 psi MW-8.9 ppg ECD's-9.13 ppg. CBU.
POOH F/212', racked back 2 stds of HWDP. P/U Flex collars. RIH to botton.
Drill ahead F/212'-T/401', starting our build section. 3.5° per/100'. P/U-28K S/O-19K ROT-25K GPM-400 SPP-900 psi RPM-40 ROP-180 TQ-2.6K WOB-2K Diff-50 psi
MW-8.9 ppg ECD's-9.13 ppg. CBU.
POOH F/401'. P/U Jar std. RIH to bottom.
Cont. directional drilling F/401'. Building 3.5° per/100'. Current depth of 774'. P/U-40K S/O-32K ROT-33K GPM-400 SPP-1037 psi RPM-60 ROP-180 TQ-3.3K WOB-2.5K
Diff-80 psi MW-8.9 ppg ECD's-9.6 ppg. Distance to well plan: 5.14' 5.08' High .83' Right.
Report Number
7
Report Start Date
6/11/2024
Report End Date
6/12/2024
Operation
Continue Drilling Surface Hole f/ 774' t/ 1531' 2-5k WOB 400 gpm 1137 psi 60 rpm 4.6k tq on bottom, 0 units of gas, MW 8.8 ppg 9.79 ppg ECD, 50K PUW 38k SOW 45k
ROT
Circulate bottoms up, obtain survey and flow check well static.
Make wiper trip f/ 1531' t/ 373' with no issues, pumped the first two stands out,
Service rig and top drive, grease crown and inspect and grease draw works, Rig smart tech adjusted system.
RIh f/ 373' t/ 1412' set down, washed and reamed to bottom, pumped HI Vis sweep around, back 2.5 bbls early 50% increaase in cuttings
Continue Drilling F/1412'-T/2026', started seeing packoff on the backream. MWD computer crashed. Pumped Low Vis/Low weight sweep while waiting for there system to
reboot. Sweep came back on time w/ a 15% increase in cuttings (clay chunks). Increased drill TQ on TDS to 16K. P/U-58K S/O-36K ROT-46K GPM-400 SPP-1228 psi
RPM-60 ROP-180 TQ-6.5K WOB-2K Diff-44 psi MW-8.9 ppg ECD's-9.6 ppg.
Resumed drilling ahead F/2026'-T/2088'. P/U-58K S/O-36K ROT-46K GPM-400 SPP-1146 psi RPM-60 ROP-180 TQ-6.8K WOB-2K Diff-69 psi MW-8.9 ppg ECD's-9.35
ppg.
Crew change, held PTSM. Cont. drilling ahead F/2088' to current depth of 2640'. P/U-68K S/O-40K ROT-54K GPM-400 SPP-1260 psi RPM-60 ROP-180 TQ-8.2K
WOB-3K Diff-68 psi MW-8.95 ppg ECD's-9.5 ppg. Distance to well plan: 16.65' 15.47' High 6.15' Left
Report Number
8
Report Start Date
6/12/2024
Report End Date
6/13/2024
Operation
Cont. drilling ahead F/2640'-T/2931'. P/U-78K S/O-40K ROT-50K GPM-400 SPP-1146 psi RPM-60 ROP-180 TQ-8.2K WOB-2K Diff-69 psi MW-8.9 ppg ECD's-9.5 ppg.
lost swab in MP #1 Pod #3, changed out w/ same.
Noticed MP #1 was leaking, shut down pumps, discovered none of the wear plate gasket were installed on MP #1. Installed gaskets. 2 hrs of NPT
Cont. drilling ahead F/2931' to TD @ 3120'. P/U-78K S/O-42K ROT-54K GPM-400 SPP-1595 psi RPM-60 ROP-180 TQ-8.9K WOB-17K Diff-263 psi MW-8.9 ppg
ECD's-9.58 ppg. Distance to well plan: 9.45' 6.76' High 6.6' Left.
CBU. GPM-400 SPP-1301 psi RPM-60 TQ-8.1K MW-8.95 ppg ECD-9.4 ppg. Flow checked well slight seepage.
Pulled wiper trip F/3120'-T/1463' with no issuse. P/U-80K S/O-44K. Calculated hole fill- 11.5 bbls Act- 12.34 bbls Diff-.84 bb ls.
RIH F/1463'-T/2959'. P/U-50K S/O-36K Set down 10K, M/U TDS, washed/reamed to bottom. Calculated pipe disp- 24.8 bbls Act- 18.5 bbls Diff- 6.3 bbls
Broke circ. filled pipe. Pumped 25 bbl Hi-Vis sweep w/ walnut/condet. Hole unloaded at BU. Sweep came back 9.5 bbls early w/ a 50% increase in cuttings. Flow checked
well- slight seepage.
POOH on elevators F/3120'-T/BHA #1 with no issues. P/U-88K S/O-44K Calculated hole fill-24.8 bbls Act-41.81 bbls Diff-17.01 bbls
Racked back HWDP, L/D jar std, and flex collars. Plugged in and down loaded MWD data. Static loss rate- 2.58 bph. L/D MWD tools. Milked mud motor, and B/O bit. Bit
graded 2-4 and a 1/8" under gage.
Cleaned & cleared rig floor. Monitored well on TT- 1 bph static loss rate. Test ran hanger (ok).
R/U TRS power tongs and handlng equip. Loaded up catwalk pipe racks w/ casing. Held PJSM on running casing.
P/U & M/U shoe track, tested floats (ok). Cont. running 7.625" 29.7# P-110 GB-CD BTC surface casing as per run tally. Current d epth of 1439'.
Report Number
9
Report Start Date
6/13/2024
Report End Date
6/14/2024
Operation
Continue RIH w/ 7 5/8'' Surface casing f/ 1439' t/ 3120' Tag bottom, L/D Jt and M/U hanger and landing jt, Land on hanger @ 3111'
Establish circulation stage rate to 5 bpm 180 psi, R/D Parker Casing equipment, and install buddy bails and clear floor, Spot i n cementers bring cement head to floor and
load plugs, M/U cement head
PJSM, pump 5 bbls water ahead, PT lines 440 low 3200 psi high, pump 60 bbls 10.5 ppg spacer @ 4 bpm 238 psi drop botom plug, pump 188 bbls 438 sks 12 ppg lead
cement 5 bpm 270 psi, followed by 33 bbls 174 sks 15.8 ppg tail cement 4 bpm 300 psi, dropped top plug, displaced w/ 135.5 bbls of spud mud and bumped plugs,
Pressured up t/ 1315 psi and held, bleed off and check floats bled back .75 bbls CIP 14:45 hrs, Blow down and R/D Cementers
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 3/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
R/D cemetn head and lines, flush stack and drain to cellar L/D cement head and L/D bail extensions, clear floor.
N/D diverter Assembly and vent line. Resealed inspection covers on MP's. Cleaned pits 1-4 & 5. Transfered new KCL mud from premix to pits 3-5.
N/U well head/tubing hanger spool as per WHR. Tested hanger neck seals/void T/5000 pis each for 15 min. Laid over beaver slide, spotted CCI crane & winch truck, pick,
craned in, and transfer BOP stack to bridge cranes. N/U spacer spool to tubing hanger spool, set stack on spool and N/U BOP's. Started mixing second batch of new KCL
mud in premix tank.
Crew change, held PTSM. Cont. N/U BOP's and mixing mud. Torqued up BOP stack bolts. Hammered up kill & choke lines, hooked up koomey lines to stack, N/U bell
nipple and installed riser. Energized koomey, funtioned rams & HCR's. Flushed & inspected centrifuge. Removed ball valves off conductor, installed caps, and gauge.
opened & inspected ram door/cavities. Installed upper/lower rams & blinds.
Report Number
10
Report Start Date
6/14/2024
Report End Date
6/15/2024
Operation
Shell test stack chase leaks on BOP equipment, mezz kill, choke flange, annular element
Test BOP's w/ 4.5'' test jt, state inspector Austin Mcleod witnessed test, all components tested t/ 250 psi low for 5 min and 5000 psi high for 10 min, Tested Annular upper
and lower rams and blinds, CMV 1-13, Auto and man IBOP, TIW and Dart, HCR and Man Choke and Kill, Perform Accumulator test and PVT and gas alarm test. Had 3
FP - Annular function retest turn up annular pressure, Kill Line flange leaking tighten a retest , Lower pipe rams function and retest.
Pulled test plug and set wear ring. Flooded stack & choke manifold, purged out air.
Pressure tested 7-5/8" surface casing T/3500 psi on a chart for 30 min (good test). Pumped in 1.9 bbls Bled back 1.88 bbls.
R/D testing equip. Blew down choke manifold & mud lines. Pulled riser, unbolted bell nipple and re-siliconed rig groove/bell nipple plate to annular. N/U same.
P/U 6-3/4" directional BHA- P/U mud motor w/ 1.5 degree bend, M/U 6-3/4" 5 bladed Varel PDC bit, Measured off set- 122.84 degrees. M/U MWD tools- DM, PCG, ADR,
ALD w/ stab, CTN, PWD, and TM collar. Plugged in and uploaded MWD data. Performed shallow pulse test (ok).
Crew change, held PTSM. Held PJSM, loaded sources. RIH w/ 3 stds of HWDP, P/U & M/U jar std. RIH w/ 5 stds of HWDP T/678'.
P/U & singled in with 74 jts of 4.5” DP of top of BHA T/2993'. P/U-65K S/O-35K
Rig service- Inspected & greased crown, blocks, wash pipe, TDS, IR, DWKS, brake linkage, and drive shaft.
RIH out of derrick F/2993', tagged TOFC @ 3022'. Drilling out 7-5/8" shoe track at current depth of 3035'.
Report Number
11
Report Start Date
6/15/2024
Report End Date
6/16/2024
Operation
Finish Drilling FE and cement t/ 3120' Drill 20' of new hole t/ 3140'
Circulate and displace well t/ 9 ppg 6% KCL Polymer mud, shut down and clean under shakers.
R/U and perform FIT t/ 13.89 ppg EMW R/D test equipment and blow down lines.
Drill Ahead 6 3/4'' Hole Section f/ 3140' t/ 3689' 250 gpm 1388 psi 80 rpm 7k tq on botom MW 9 ppg ECD 10.2 ppg Max Gas 7 units 69k PUW 40k SOW 53k ROT 54K.
Obtained new SPR's @ 3034'.
Cont. directional drilling 6-3/4" production hole F/3689'-T/4061'. P/U-78K S/O-46K ROT-58K GPM-250 SPP-1450 psi RPM-80 WOB-3K Diff-95 psi TQ-7.5K ROP-180 fph
MW-9.05 ppg ECD-10.16 ppg Max gas-343 units.
Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/4061'-T/4123'. P/U-78K S/O-46K ROT-58K GPM-250 SPP-1330 psi RPM-80 WOB-1/2K
Diff-51 psi TQ-7.5K ROP-77 fph MW-9.1 ppg ECD-10.3 ppg Max gas-149 units.
CBU. Shot on bottom survey, obtanied new SPR's flow checked well- Slight seepage. GPM-250 SPP-1356 psi RPM-80 TQ-7.2K
Pulled wiper trip F/4123'-T/3119'. Started swabbing @ 3325' with no over pull. Performed 10 min flow check- slight seepage. P/U-80K S/O-50K
Rig service- Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive shaft. Inspected saver-sub (ok). Cleaned suction screens on MP's.
Static loss rate- .8 bph.
RIH on elevators F/3119'-T/3156'. Set down 15K, attempted to work through on elevators w/ no luck. Washed/reamed F/3135'-T/3182'. RIH on elevators F/3182'-T/3332'.
Set down 15K, attempted to work through on elevators w/ no luck. Washed/reamed F/3308'-T/3874'. Shaker unloaded with super fines. RIH on elevators F/3874'-T/4061'.
Washed last std to bottom. GPM-250 SPP-1249 psi RPM-60 TQ-6.2K MW-9.05 ppg ECD-10.2 ppg Max gas- 209 units.
Pumped 20 bbl Hi-Vis sweep w/ walnut/condet. Currently cirulating sweep around. GPM-250 SPP-1280 psi RPM-80 TQ-6.5K
Report Number
12
Report Start Date
6/16/2024
Report End Date
6/17/2024
Operation
Drill Ahead 6 3/4'' Hole Section f/ 4123' t/ 4278' 250 gpm 1505 psi 80 rpm 7k tq on bottom, 2-4k WOB, Max Gas 47 units, 79k PUW 49k SOW 60k ROT MW 9.05 ppg
ECD 10.2
Continue Drilling Ahead 6 3/4'' Hole Section f/ 4278' t/ 4698' 250 gpm 1600 psi 80 RPM 8.4k tq on bottom, MW 9.05 ppg ECD 10.3 ppg, 82k PUW 50k SOW 62k ROT
Cont. directional drilling 6-3/4" production hole F/4698'-T/5047'. Pumped 25 bbl Hi-Vis sweep with walnut/condet @ 4698' while drilling ahead, sweep came back 6 bbls
early with a 100% increase in cuttings. P/U-88K S/O-50K ROT-64K GPM-250 SPP-1783 psi RPM-80 WOB-4K Diff-205 psi TQ-9K ROP-180 fph MW-9.1 ppg ECD-10.77
ppg Max gas-186 units.
Crew change, held PTSM and weekly safety meeting with rig crew. Cont. directional drilling 6-3/4" production hole F/5047' to wi per trip depth at 5359'. Pumped 25 bbl
Hi-Vis sweep around while drilling last std. down, sweep came back 12.5 bbls early with a 60% increase in cuttings. Shot on bot ttom survey. Obtained new SPR's and
flow checked well- slight seegage. P/U-97K S/O-55K ROT-69K GPM-250 SPP-1894 psi RPM-80 WOB-3/6K Diff-209 psi TQ-9K ROP-100/180 fph MW-9.15 ppg
ECD-11.3 ppg Max gas-294 units. Distance to well plan: 5.96' 2.18' High 5.55' Left
Pulled wiper trip F/5359' to current depth of 4057'. P/U-108K S/O-60K
Report Number
13
Report Start Date
6/17/2024
Report End Date
6/18/2024
Operation
Continue POOH making wiper trip f/ 4057' t/ 3056' with out issues
Service rig and top drive, Grease crown and draw works
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 4/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
RIh P/U 50 jts of DP f/ 3056' t/ 4625' had to was and ream through tight spot f/ 3521' t/ 3706' Continue RIH w/ remaining DP f/ derrick t/ 5359' Circulate Hi Vis sweep
around hole unloading on bottoms up, Sweep back on time 10% increase in cuttings
Drill ahead 6 3/4'' Hole section f/ 5359' t/ 5814' 250 gpm 2100 psi 80 rpm 10.6k tq on bottom, 7k WOB, 893 units of gas observed, 104k PUW 58k SOW 72k ROT
Cont. directional drilling 6-3/4" production hole F/5814'-T/6079'. Pumped 25 bbl Hi-Vis sweep with walnut/condet @ 5828' while drilling ahead, sweep came back 12.5 bbls
early with a 75% increase in cuttings. Obtained new SPR's @ 5875'. P/U-114K S/O-58K ROT-74K GPM-250 SPP-2278 psi RPM-80 WOB-8K Diff-381 psi TQ-10.4K
ROP-180 fph MW-9.25 ppg ECD-10.96 ppg Max gas-418 units.
Off line strapped & tallied 3.5" 9.2# L-80 Wedge 563 liner.
Crew change, held PTSM. Cont. directional drilling 6-3/4" production hole F/6097' to current depth of 6510'. P/U-120K S/O-63K ROT-80K GPM-250 SPP-1949 psi
RPM-80 WOB-5/6K Diff-157 psi TQ-11.5K MW-9.25 ppg ECD-11.1 ppg Max gas-285 units. Distance to well plan: 4.50' 1.33' Low 4.30' Left
Report Number
14
Report Start Date
6/18/2024
Report End Date
6/19/2024
Operation
Continue Drilling 6 3/4'' Hole Section f/ 6510' t/ 6552' 250 gpm 1960 psi 80 rpm 11.3k tq on bottom, 120k PUW 61k SOW 80k ROT
Circulate bottoms up, obtain survey and SPR's, flow check well slight loss dropped 10'' in stack
Pull wiper trip f/ 6552' t/ 5315' no issues.
Service rig and draw works, clean suction screens.
RIH f/ 5315' t/ 6552' with no issues, wash last stand to bottom
Pump Hi Vis Sweep around Back 150 stks early 15% increase in cuttings
Drill Ahead 6 3/4'' hole section f/ 6552' t/ 7117' 250 gpm 1842' psi 80 rpm 12k tq on bottom, 5k WOB, PUW 132 SOW 62k ROT 85k Max Gas 823 Units
Drill Ahead 6 3/4'' hole section f/ 7117' t/ 7559' 250 gpm 2069' psi 80 rpm 13.8k tq on bottom, 6k WOB, P/U-140k, S/O-66k ROT-90k Max Gas-2168 Units. Perform 200
bbl dump and dilute at 7368'. MW-9.15ppg.
Drill Ahead 6 3/4'' hole section f/ 7559' t/ TD at 7654' 250 gpm 2069' psi 80 rpm 13.8k tq on bottom, 6k WOB, P/U-145k, S/O-69k, ROT-89k Max Gas-342 Units.
CBU x 2 245GPM=1707PSI, 80RPM=13.6K TQ Max gas=717 units. Take final survey. Obtain SPR and flow check well observed slight flow.
Circulate while wieght up mud system to 9.5ppg 240GPM=1650PSI, 80RPM=13.7k TQ. Max gas 29 units.
Report Number
15
Report Start Date
6/19/2024
Report End Date
6/20/2024
Operation
Continue weighting up system to 9.5 ppg MW, Flow check well f/ 20 min well static slight loss dropped 6'' in stack
POOH f/ 7654' t/ 6547' Pulling tight seeing some differential sticking 20-40k overpulls, BROOH f/ 7492' t/ 6547'
Service the rig and top drive, grease blocks and crown, clean suction screens on MP 10% blocked off
RIH f/ 6547' t/ 7654' Wash last stand to bottom No hole issues
Pump Hi Vis/Lube Sweep around add 2 drums of lube to suction pit to chase, sweep back 105 stks early 10% increase in cuttings, Flow check well static slight loss
POOH f/ 7654' t/ 2390' wash and ream through tight spot @ 6351'
POOH f/2390' t/ BHA.
PJSM with crew on removing nuclear sources and handling BHA. Download data from MWD tools. Reconfigure BHA- L/D PWD and ALD/CTN. Static loss rate of
1.3bbl/hr.
P/U Geotap and confidence test tools. Simop: Perform rig service and finish rigging up geospan. MWD had issues uploading the to ol but eventually got it to work, but
while performing the shallow pulse test they were getting no responses from the tool. Plugged back into the tool but could not get it working again. Decision made to L/D
BHA and run liner. Bit Graded:1-1-WT-A-X-I-NO-TD.
Service and inspect crown, blocks top drive, iron rough neck, drawworks, chain case, gear box, drive line, brake linkage, and floor motor . Clean suction screens on MP 1
& 2.
RIH w/ HWDP and jars to come out laying down.
Report Number
16
Report Start Date
6/20/2024
Report End Date
6/21/2024
Operation
Continue RIH w/ HWDP and Jar stand f/ derrick, POOH L/D HWDP and Jars, clear floor R/D Geo Span Unit
Pull Wear Ring, set test plug and fill stack, Test Upper and Lower Rams t/ 250 low f/ 5 min and 3000 high f/ 10 min Test Annular t/ 250 low 5 min and 2500 p high f/ 10
min all with 3.5'' test jt, R/D test equipment pull test plug set wear ring.
R/U Parker Casing equipment, Have PJSM with crew
P/U Float equipment RIH check floats good, continue RIH w/ 3.5'' HYD 563 Liner as per detail installing centrralizer every jt t / 3086'
M/U circulating swedge, circulate bottoms up 5 bpm 328 psi
Cont to RIH w/3.5" liner f/3086' t/4742'. Change out elevators, P/U and M/U liner hanger as per YJ and Innovex reps. M/U stand of 4.5" DP. P/U-41K, S/O 30K.
CBU. At 1700 strks seen a Max of 5505 units of gas. Gas units fell to 2681 before and climbed to 5126 units at BU. 4bbl/min = 435PSI
Cont to RIH w/3.5" liner conveyed on 4.5" DP f/4742' t/6165'. Screw into string to circulate gas out. P/U-43K, S/O 32K.
CBU. At 1700 strks seen a Max of 5385 units of gas. Gas units fell to 1358 and climbed to 3851 units at BU. 4bbl/min = 470PSI
Cont to RIH w/3.5" liner conveyed on 4.5" DP f/6165' t/7654'. Screw into string to was last stand down P/U-88K, S/O 54K. Tight spot at 7512' (wash f/7484' t/7548').
1bbl/min 370PSI.
CBU x 2 at 4bbl/min 585PSI. Max gas 5360 units. P/U-88k, S/O-54k. Mud weight 9.7ppg. Circulate and codition mud until 9.5ppg In/Out
Report Number
17
Report Start Date
6/21/2024
Report End Date
6/22/2024
Operation
Continue Circulating and condition mud bring MW t/ 9.55 ppg in and out
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 5/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
P/U cement head and M/U circulating lines, run wash up line to cuttings box.
Pump 5 bbls of water ahead, PT Lines t/ 400 psi Low 4400 psi High, Pump 30 bbls of spacer, followed by 185 bbls of lead cement 12 ppg, Pump 24 bbls tail cemnt 15.3
ppg, wash up to cuttings tank over top of plug, Drop plug and displace w/ 77.5 bbls of mud, did observe pressure increase as pl ug went through running tool had to
pressure up to 2000 psi to sent through, Bumped plugs @ 2 bpm 1625 psi pressure up to 2125 psi bleed off and check floats good,
Set Liner Hanger as per Yellow Jacket and Innovex rep, pressure up to 2400 psi and set hanger packer, observe shift @ 2200 psi, set down 50k on anchor and set P/U t/
15k over nuetral weight and increase pressure to 3600 psi observe weight drop off to 45k P/U on string still attached , slack off to 30k P/U on string still attached to liner,
slack off to 30k P/U and string free travel, L/D Cement head and circulating lines, kelly up to string and P/U 35' clear liner and circualte bottoms up X2 @ 9.7 bpm 400 psi
POOH f/ 2835' to surface L/D Running tool dog sub sheared, P/U and break down cement head
Flush stack with black water function rams, and flush clean.
Service rig and top drive, grease blocks and crown, inspect draw works and check floor motor
M/U polish mill assembly RIH to tag liner top at 2877', land out on no go at 2911'. Dress liner top and polish TBR as per YJ rep. 4RPM=2.4k TQ, 133GPM=283PSI.
P/U-43K, S/O-33K, ROT=35K.
Displace well over to CI water. Displacement volume 20bbl spacer, 210 bbls CI water. 259GPM=704PSI,
Perform negative pressure test-good.
POOH f/2855' t/ surface laying down 90 jnts of 4.5" DP. L/D Polish mill assembly.
R/U and perform pressure test on liner top packer. Observed leak down on first test. Purge lines and line up through choke manifold Pressure up two more times
observing the same results. Isolate surface equipment and test same- no leaks found. Pressure up and test for 45 minutes-good test. R/D test equipment.
Report Number
18
Report Start Date
6/22/2024
Report End Date
6/23/2024
Operation
RIH w/ stands of DP f/ derrick, POOH L/D DP repeat until all DP L/D
Pull wear ring, R/U to run 3.5" completion, R/U parker tubing equipment.
M/U seals and RIH t/ 1337' M/U Chemical injection mandrel, terminate control line and test to 1000 psi f/ 10 min good. Continue RIH w/ completion putting 1 band per jt
t/2091'. P/U tag joint and had issues getting past 2091, had to rotate string one turn to get past, tag with end of seal assemb ly at 2914.75' (no-go at 2904.11'). L/D two jnts
and M/U space out pups A and E on bottom of first full jnt. M/U hanger and run in hole, had issues gettng past 2901' again work string and able to get past. Land out with
no-go 0.88' off seat, hanger set snap ring and pull test with 3k to confirm set. P/U-29k, S/O-23k.
R/U test equipment on 3.5" tubing and perform MIT-T 3000psi/30min charted, pumped 0.68bbl, bled back 0.67-good test. R/U test equipment on 7-5/8" x 3.5" and perform
MIT-IA 3000psi/30min charted, pumped 1.39bbl bled back 1.37bbl-good test. Test witnessed by BLM inspector Quinn Sawyer.
Flush CI water through surface lines and equipment. Flush baraclean through surface lines and equipment and blow down same.
Remove chains from BOP. Pull riser and mouse hole. Remove bell nipple and flow line. Open ram doors for inspection.
Report Number
19
Report Start Date
6/23/2024
Report End Date
6/24/2024
Operation
Finish Ram inspection button up doors, N/D stack and transfer to bridge cranes, and remove from cellar with crane, spot in well head and N/U as per wellhead rep, test
void and hanger neck seals top 5000 psi f/ 10 min. remove flow box from cellar.
Pull chain case covers, inspect and reseal hatches, finish cleaning pits, clear rig floor, disassemble mud pump fluid ends and inspect, fix leak on hyd line in derrick, from
top drive HPU, continue prepping to lay down top drive, R/D modules and prep to move.
Disconnect third party shacks from rig power. Changed oil in gear box and swivel on top drive. R/D and L/D top drive.
Clean and organize throughout rig. Wash derrick, floor, carier, drawworks, top drive, pits, pump room, and lube room. Inventory pump parts and miscellaneous
compnenets for rig.
Report Number
20
Report Start Date
6/24/2024
Report End Date
6/25/2024
Operation
Continue R/D Modules, Rig movers pulled pit and pump modules and staged out of the way, Scope down derrick, L/D torque tube and fold over skate ramp, Pull skate
and mats out, Pull top drive HPU
Spool off drilling line and prep derrick to Lay over, TMC on location grading pad for move, Lay over derrick and prep to move, Pull gen and dog house away from sub,
compact location and prep f/ felt liner and mats
Lay felt, liner and rig mats. Install metal grating on cellar. Install diverter T and surface annular. Remove gen house from rig mats. Change oil on camp gen. Remove
water tank and top drive HPU from rig mats.
Perform derrick inspection. Pick up around location. Clean and organize gen house. Rig released at 06:00.
Report Number
21
Report Start Date
8/14/2024
Report End Date
8/14/2024
Operation
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 1/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:7/1/2024 End Date:
Report Number
1
Report Start Date
6/30/2024
Report End Date
7/1/2024
Operation
Report Number
2
Report Start Date
7/1/2024
Report End Date
7/2/2024
Operation
Report Number
3
Report Start Date
7/2/2024
Report End Date
7/3/2024
Operation
PJSM, Crew travel to location, Function test all BOPE components & fill reel.
Pressure test BOPE 250/2500 as per sundry & perform acumilator draw down.
Perform maintence on equipment while waiting on tool hand.
Make up coil connector & test, Pull test @ 10k & 25k, Pressures test to 3k, Make up bha as follows: connector x 1, dual flapper x 1, disco x 1, circ sub x1, motor x 1, XO x
1, 2.75" bit, Length: 15.70'
Run in the hole to tag @ 7485', Clean out to 7600'. Circulate hole clean. Pull out of hole to swap bha.
Pick up and make up reverse nozzle, Run in hole. Unload hole returned 86 bbls with 92996 scfs. Pull out of the hole.
Rig down & release.
Report Number
4
Report Start Date
7/11/2024
Report End Date
7/12/2024
Operation
PJSM, Crew travel to location, Spot in & rig up, Pick up lube & CCL/GPT, Pressure test 250/2500-leak at top flange, Tighten and retest 250/2500-good
Run in hole with CCL/GPT to tag @ 7520', No fluid detected. Pull out of hole & lay down tools.
Pick up & run in hole with Run #2, Run in hole & hang up at 4470' work down to 4570', Unable to pass, Pull out of the hole.
Secure well, Lay down & inspect tool string.
Report Number
5
Report Start Date
7/12/2024
Report End Date
7/13/2024
Operation
PJSM, Crew travel to location, Pick up lube & CCL/GR/ 2-1/2" x 10' gun, Stab onto wellhead & pressure test 250/2500-good test.
Run in hole with run #1, CCL/GR/ 2-1/2" x 10' gun, Tag @ 4437', Unable to pass, Pull out of hole.
Pick up Run #2, CCL/GR (2.75"), Run in hole & tag @ 4528' (0L:14'), Work multiple times. Unable to pass. Pull out of hole
Pick up Run #3, CCL/GR/10' x 2-1/2" gun, Run in hole to 7465', Log up from 7450' to 6100', Correlate as per GEO, Perf the BEL I10 f/ 6974-6984, OG psi: 1553, 5 min:
1552, 10 min: 1549, 15 min: 1562, Pull out of hole.
*2-1/2", 60 deg, 15 gr, 6 spf
Pick up Run #4, CCL/GR/20' x 2-1/2" gun, Run in hole & correlate, Perf the BEL J4 F/ 7383-7399, OG psi: 1509, 5 min: 1511, 10 min: 1514, 15 min: 1520, Pull out of hole.
*2-1/2", 60 deg, 12 gr, 6 spf
Charges P/N# RTG-2512-421T
Pick up Run #5, CCL/GR/10' x 2-1/2" gun, Run in hole & correlate, Perf the BEL H13 F/ 6350-6360, OG psi: 1558, 5 min: 1591, 10 min: 1617, 15 min: 1614, Pull out of
hole.
*2-1/2", 60 deg, 12 gr, 6 spf
Charges P/N# RTG-2512-421T
Pick up Run #6, CCL/GR/17' x 2-3/8" gun, Run in hole & correlate, Perf the BEL H11 F/ 6295-6312, OG psi: 1409, 5 min: 1444, 10 min: 1463, 15 min: 1492, Pull out of
hole.
*2-3/8", 60 deg, 10.8 gr, 6 spf
Charges P/N# RTG-2512-421T
Shut in & secure well lay down tool string.
Report Number
6
Report Start Date
7/13/2024
Report End Date
7/14/2024
Operation
PJSM, Crew travel to location, Reahead, Pick up lube and tool string, Pressure test 250/2500-good, Draw well down from 2410 psi to 1540 psi.
Run in hole with Run #1, Run in to 7400' no fill, Pull up & correlate, Perf BEL H10 (6269-6275), Flowing well with 1439 psi to 1418 psi.
*2-1/2", 60 deg, 12 gr, 6 spf
Charges P/N# RTG-2512-421T
Run in hole with Run #2, Correlate, Perf BEL H10 (6250-6262) while flowing, Pull out of hole.
*2-1/2", 60 deg, 12 gr, 6 spf
Charges P/N# RTG-2512-421T
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #: 324-364
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:224-035
Page 2/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
Run in hole with Run #3, Correlate, Perf BEL H8 (6167-6187) while flowing whp 1438, Pull out of hole.
*2-1/2", 60 deg, 12 gr, 6 spf
Charges P/N# RTG-2512-421T
Run in hole with Run #4, Correlate, Perf BEL H8 (6150-6167) while flowing, Pull out of hole.
*2-3/8", 60 deg, 10.8 gr, 6 spf
Charges P/N# RTG-2512-421T
Run in hole with Run #4, Correlate, Perf BEL H7 (6123-6131) while flowing, Pull out of hole.
*2-1/2", 60 deg, 10.8 gr, 6 spf
Charges P/N# RTG-2512-421T
Rig down AK eline
Report Number
7
Report Start Date
7/15/2024
Report End Date
7/16/2024
Operation
PJSM, Crew travel to location, Spot in & rig up, Wait on PLT tools to arrive, PIck up lube & tool string, Pressure test lube 25 0/2500-good.
Run in hole with run #1, CCL/GR/PLT, Log down and perform PLT passes as per OE, Pull out of hole and change spinners & run in hole to continue logging. 40 up &
down, 80 up & down, 120 up & down, Pull out of hole.
Secure well & lat down tools and equipment.
Report Number
8
Report Start Date
7/16/2024
Report End Date
7/17/2024
Operation
PJSM, Crew travel to location, Pick up lube & run #1, Stab onto wellhead & perf
Pick up run #1, CCL/GR/ GUNS (Gun #1 & Gun #2), Run in hole, Correlate from 6200-4990', Pull up to perf BEL 4 (6000-6006), OG psi: 1473, 5: 1488, 10: 1504, 15:
1516, Pull up to perf 2nd gun @ BEL H3 (5974-5980), OG psi: 1532, flowing, Pull out of the hole
*2-1/2", 6 spf, 12 gr, 60 deg.
Bull plug: Soupy no sand
Pick up run #2, CCL/GR/ GUNS (Gun #3 & Gun #4), Run in hole, Pull up to perf BEL H2 (5923-5937), OG psi: 1117, Pull up to perf 2nd gun @ BEL H (5849-5856), OG
psi: 1110, Pull out of the hole
*2-1/2", 6 spf, 12 gr, 60 deg.
Bull plug: Soupy no sand
Pick up run #3, CCL/GR/ GUNS (Gun #5 & Gun #6), Run in hole, Pull up to perf BEL G9 (5776-5781), OG psi: 744, Pull up to perf 2nd gun @ BEL G6 (5700-5708), OG
psi: 743, Pull out of the hole
*2-1/2", 6 spf, 12 gr, 60 deg.
Bull plug: Soupy no sand
Unable to move string, Shut in well & work line f/ 250 lbs to 1900 lbs. Starting pressure 741 psi, build rate 20 psi/min to 969 psi. Worked string free Pull out of hole &
inspect tools. Bull plug full of very fine sand.
Rehead & pick up run #4, CCL/GR/ GUNS (Gun #7 & Gun #8), Run in hole, Pull up to perf BEL G4 (5682-5687), OG psi: 744, Pull up to perf 2nd gun @ BEL G4
(5641-5648), OG psi: 743, Pull out of the hole
*2-1/2", 6 spf, 12 gr, 60 deg.
Bull plug: Soupy no sand
Secure well & lay down tools for the night
Report Number
9
Report Start Date
7/17/2024
Report End Date
7/18/2024
Operation
PJSM, Crew travel to location, Pick up lube & guns (8 & 9), Stab onto well, Pressure test lube 250/2500-good.
Run in the hole with run #1 CCL/GR/GUNS (8 & 9), Run in hole & tag @ 6268', Correlate, Drop down & Perf G3 (5612-5618), Pull up hole, Perf G3 (5585-5591), Pull out
of the hole & lay down tools.
*2-1/2", 6 spf, 12 gr, 60 deg
Pick up run #2, CCL/GUNS (2-3/8" x 20'), Run in hole, Correlate, Perf G2 (5554 to 5574) OG psi: 519, Pull out of the hole. work string up caught at 5445 multiple times,
shut in well & hold tension and work string up & down till free. Pull out of hole to sureface, Secure well.
*2-3/8, 6 spf, 10 gr, 60 deg.
Rig down & prep to move
Report Number
10
Report Start Date
7/18/2024
Report End Date
7/19/2024
Operation
PJSM, Crew travel to location, Spot in & rig up SL, Pick up lube & 2.25" bailer, Pressure test 250/2500-good.
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #: 324-364
State: ALASKA
Rig/Service:
Page 3/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
Run in hole with 2.25" bailer to tag @ 5940', Pull out a full bailer (fine sand), RIH W/ Same to 5940'KB- W/T - Lose spang & jar action- Work line up to 1400# & Rupture
weight pod diaphram- repair unit- Continue to work wire & gain downhole movement to 5976'KB- bridge above rope socket @ 5938'KB- begin beating up from below to
5870'- No more movement- Begin lift assist while maintaining 1500# bind on wire- Begin moving up hole at 1300# till 3820'KB
Shut in well to build pressure, Build to 1045 lbs, Open well & flow while continuing to work bailer on bottom, Bailer free, Pul l out of the hole, bailer full, Pick up 2.65" & run
in hole to tag @ 3468', Pull out of the hole & secure well.
Rig down for the night
Report Number
11
Report Start Date
7/19/2024
Report End Date
7/20/2024
Operation
Perform JSA- Gain permit approval- Depart for pad, Arrive on location- Slip & Cut 100' of wire- perform wire test- test good- Re-head & begin stand up, RIH W/ 2.5 DDB to
3378'KB- W/T- 3386'KB- POOH W/ Full clay & coal, RIH W/ Same to 3386'KB- W/T- 3392'KB- POOH W/ Full clay & coal, RIH W/ Same to 3391'KB- W/T- 3399'KB -
POOH W/ Full clay & coal, RIH W/ Same to 3399'KB- W/T- 3404'KB- POOH W/ 1/2 Full clay & coal, RIH W/ Same to 3403'KB- W/T- 3408'KB- POOH W/ 1/2 Full clay &
coal, RIH W/ Same to 3408'KB- W/T- 3411'KB- POOH W/ 1/4 Full clay & coal ,RIH W/ Same to 3405'KB- W/T- 3413'KB- POOH W/ Muddy s lurry, RIH W/ 2.25 DDB to
3407'KB- W/T 3414'KB- POOH W/ Muddy slurry, RIH W/ 2.25 DDB to 5720'-W/T- Fall to 5940'KB- Tag- POOH, RIH W/ 2.7 GR to 5330'KB- W/T- Fall to 5939'KB- Tag-
POOH, Begin Lay down- hand well to production & secure equipment for the evening
Report Number
12
Report Start Date
7/20/2024
Report End Date
7/21/2024
Operation
Morning meeting, Perform JSA- Gain permit approval- Depart for pad, , Arrive on location- Re-head- Begin Stand up on well, Stan dby for SV closure test, RIH W/ 2.5 DDB
to 5522'KB- W/T Lose spangs & Jars- Pull 1400# bind and come free- POOH W/ 1/2 Full Sand & Clay, Gather triplex & Diesel- Pump 1 BBL Diesel, RIH W/ 2.5 DDB to
5483'KB- W/T- 5488'KB- POOH W/ Full Sand, RIH W/ Same to 5474'KB- W/T- 5482'KB- POOH W/ Full sand, RIH W/ Same to 5470'KB- W/T- 5478'KB- POOH W/ 1/2
Full sand, RIH W/ Same to 5466'KB- W/T -5477'KB- POOH W/ 1/2 Full sand, Standby to bring on well, Establish rate, RIH W/ 2.5 DD B to 5850'KB- POOH- Hang up @
5120'- Work free & Continue OOH W/ Empty, Begin Lay down for the evening, Depart for camp
Report Number
13
Report Start Date
7/21/2024
Report End Date
7/22/2024
Operation
PJSM, Crew travel to location, Pick up lube and 2.72" gr, Stab onto well.
Run in hole to tag @ 5258' w/ 2.72" GR, Pull out of hole, Flow well to line pressure 308 psi. Run in hole & tag @ 6287', Pull o ut of hole.
Rig down slickline, Rig up AK Eline, Pick up lube & CCL/GR/PLUG (2.5"), Run in hole, Correlate, Set plug @ 5626', Attempt to tag (no tag), Pull up on depth & attempt to
reset (no success). Pull out of hole to inspect tool string.
Pull into liner top @ 2909' plug hung up in liner top, Work string, Unable to free, Pull out of rope socket, Pull out of the ho le.
Rig down AK Eline, spot in & rig up Pollard slick line, Pick up lube and LIB.
Run in hole to 6195' with 2.32" lib & tag, Pull out of hole.
Pick up 2.77" GR & run in hole to 6195'. Tag - Hang up @ 2870' - WT -Pull out of hole & lay down tools for the night.
Rig down slick line for the night.
Report Number
14
Report Start Date
7/22/2024
Report End Date
7/23/2024
Operation
PJSM, Crew travel to location, Pick up lube and 2.75" GR, Stab onto well
Run in hole with 2.75" GR, Tag @ 6185', Pull out of hole , hang up @ 2869', Work thru max over pull 1500 lbs, Pull out of hole (missing 2.75" GR & junk basket), Discuss
forward plan, Pick up & run a 2.32" LIB run in hole & tag 5939', sticky off bottom (300# overpull), Pull out of hole, slowing d own at 3000 ft and no issues at liner top, While
bumping up line broke & tool string fell to bottom. Ball of wire in lubricator, Lay down slick line assembly.
Rig down slickline and rig up Eline, Pick up lube and CCL/PLUG (2.75"), Pressure test lube 250/2500-good.
Run in hole run #1, CCL/PLUG (2.75"), run in hole & correlate, Get on setting depth @ 5622', Shoot plug, log off, go for tag (no tag) log down to 5900' no tag, Pull out of
hole to 2909' CCL/depth unable to pull up.
Work string up & down, staging from 500, 800, 1200, 1500 lbs up, lose movement down, Attempt to work string, no up or down movement, Build well pressure to 950 psi,
Open wide open, close let pressure build. Discuss with town further options, Pull out of rope socket 2870 lbs.
Rig down eline for the night
Report Number
15
Report Start Date
7/26/2024
Report End Date
7/26/2024
Operation
Arrive at ship. Gather tools & Personnel- Depart for hangar.
Arrive @ Hanger-Standby for flight
Depart for Beluge
Arrive @ Beluga- Camp assignment/Dress out
Perform JSA- Gain permit approval- Depart for D-pad- Gather equipment- Depart for H-Pad
Arrive on location- Begin R/U
PT to 2500#- Test good
RIH W/1.8" LIB to 5680'KB- Tag POOH- Hang up @ 4820'KB- No action- free downward movement- hold 1500# bind- come free- Continue OOH- Hand up at 4330'KB-
3300'KB & 2490'KB-OOH W/Blank LIB face- Likely fill
Begin Lay down- Secure well & Equipment for the evening.
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #: 324-364
State: ALASKA
Rig/Service:
Page 4/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Report Number
16
Report Start Date
7/27/2024
Report End Date
7/27/2024
Operation
Morning Meeting
Depart for H-Pad
Arrive on location- Begin R/D
Standby for flight
Depart for shop
Report Number
17
Report Start Date
7/30/2024
Report End Date
7/30/2024
Operation
Report Number
18
Report Start Date
8/6/2024
Report End Date
8/7/2024
Operation
PJSM, Crew travel to PCU & mob equipment to pad, Spot in & rig up, Pick up lube & tools (max id: 2.125"), Pressure test 250-2500-good.
Run in hole with run #1 (CCL-2.125", wt bars- 2", 1-11/16", rope socket-1.375", Centrilizers-5-1/2") run in hole to stick @ 613 ', Pull out of the hole, Remove centrilizers, Re
run in hole work thru linere top multiple times-no isses, run in hole to tag @ 6205', Fell thru bridge @ 5880', Pull out of hol e to surface.
Secure well & rig down for the night.
Report Number
19
Report Start Date
8/7/2024
Report End Date
8/8/2024
Operation
PJSM, Crew travel to location, Pick up lube & tool string, Pressure test 250/2500-good.
Run in hole with run #1 (1 x 3 blade box cent, 1-11/16" wt bar, logging centrilizer, 1-11/16 wt bar, 1 x logging cent, 2" wt ba r, 2-1/18" CCL PLugged) Run in hole to 5800',
Pull out and have 200-400 lbs over pull from 5640-5300, pull out of the hole to surface.
Make up caliper tools and calibrate.
Run in hole with run #2 with calipers, work thru 2909 to 2950, Open calipers run thru liner top, No issues, Run down hole to tag 3660', Pull up into lube & flow well.
Flow well to clean up bridges.
Run in hole with run #3 with calipers, Run down hole to tag 3357', Work thru tight spot, continue going down to tag @ 6202', Attempt to open arms, Unable to open arms,
Pull out of hole, Check tool (packed with sand),
Pick up & make up run #4, CCL/GUN (5' gun). Run in hole & correlate, Perf the G4 (5549-5554), OG: 358 psi, Pull out of the hole.
Rig down & release AK Eline.
Report Number
20
Report Start Date
8/15/2024
Report End Date
8/16/2024
Operation
PJSM, Crew travel to location, Spot in & rig up, Pick up lube & GPT, Pressure test 250/2500-good.
Run in hole with run #1, CCL/GPT (Max OD: 1.69), Suspended columns of fluid, Tag @ 6202, Log up & send log to town, Pull out of hole.
Pick up & make up run #2, Run in hole, Correlate, Perf the G1 (5521-5533), Pull out of hole.
**2-3/8", 11.5 gr, 6 spf, 60 deg.
Pick up & make up run #3, Run in hole, Correlate, Perf the F10 (5438-5443), Pull out of hole.
**2-3/8", 11.5 gr, 6 spf, 60 deg.
Pick up & make up run #4, Run in hole, Correlate, Perf the F10 (5414-5419), Pull out of hole.
**2-3/8", 11.5 gr, 6 spf, 60 deg.
Secure well & rig down for the night.
Report Number
21
Report Start Date
8/16/2024
Report End Date
8/17/2024
Operation
PJSM, Crew travel to location, Pick up Lube & tool string (CCL/GR/GUN), Pressure test 250/2500-good.
Pick up run #1 (CCL/GR/GUN)(6'), Run in hole, Correlate, Perf BEL F7 (5366-5372), OG PSI: 349, Pull out of hole to 4330', Unable to move gun.
**2-1/2", 12 gr, 6 spf, 60 deg
Work string while manipulating well flow,
550 psi working 1900 to 200 lbs pull
300 psi wortking 1900 to 200 lbs pull
Work string up in 100 lb increments x 3 times with 250 psi whp.
Pull out of rope socket @ 2600 lbs, Pull out of the hole.
Secure well & rig down
Report Number
22
Report Start Date
8/17/2024
Report End Date
8/18/2024
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #: 324-364
State: ALASKA
Rig/Service:
Page 5/5
Well Name: BRU 222-26
Report Printed: 8/28/2024www.peloton.com
Well Operations Summary
Operation
PJSM, Crew travel to location, Spot in & rig up, Pick up lube & tool string, Pressure test 250/2500-good.
Run in hole with 2.5" LIB, Tag @ 4003', Pull out of hole, Unload well, Pick up 2.25" bailer & run in hole to 4300' (no tag), Pu ll out of the hole, Pick up 2.5" LIB tag @ 6008',
Pull out of hole & evaluate, Pick up overshot & run in hole to tag @ 5608', Pull out of hole, Run in hole with 2.25" bailer to 6011', Pull out of hole bailer full of sand, Pick up
2.5" bailer & run in hole, Tag @ 6011', Pull out of hole bailer half full, Pick up RKB run in hole tag @ 6011', No latch, Pull out of hole, Make up 2.5" bailer run in hole, Tag
@ 6013', Pull out of hole, Bailer 1/3 full, Pick up 2.62" overshot & run in hole, Latch at 6013', Work string & jars till shear , Pull out of hole & rebait, Run in hole to latch on
at 6011', Work & jar till shear, Pull out of hole & rebait run in hole & engage fish @ 6013', Work & jar till shear, Pull out of the hole & secure well for the night.
Rig down for the night.
Report Number
23
Report Start Date
8/18/2024
Report End Date
8/19/2024
Operation
PJSM, Crew travel to location, Restring lube & head to .16 wire, Pick up lube & tool string, Pressure test 250/2500-good.
Run in hole to tag fish @ 6011', work tools to engage fish, Work string from 0 to 3500 lbs with jars, till shear. Pull out of h ole & secure well.
Rig down slickline, Spot in & rig up eline.
Report Number
24
Report Start Date
8/19/2024
Report End Date
8/20/2024
Operation
PJSM, Crew travel to location, Pick up lube & tool string, Pressure test 250/2500-good.
Run in hole with run #1, (CCL/GR/GUN)(4'), Correlate, Perf BEL F7 (5340-5344), OG psi: 467, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Flow well @ 1.5 mmcf to clean up wellbore.
Run in hole with run #2, (CCL/GR/GUN)(4'), Correlate, Perf BEL F7 (5270-5274), OG psi: 512, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Flow well @ 1.5 mmcf to clean up wellbore.
Run in hole with run #3 CCL/GPT, Run in hole to 5300. Pull out of hole.
Run in hole with run #4, (CCL/GR/GUN)(6'), Correlate, Perf BEL F6 (5216-5222), OG psi: 670, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Flow well @ 1.5 mmcf to clean up wellbore.
Run in hole with run #5, (CCL/GR/GUN)(3'), Correlate, Perf BEL F6 (5188-5191), OG psi: 448, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Secure well & rig down for the night
Report Number
25
Report Start Date
8/20/2024
Report End Date
8/21/2024
Operation
PJSM, Crew travel to location, PIck up CCL/GUN, Pressure test 250/2500-good.
Run in hole with run #1, (CCL/GR/GUN)(6'), Correlate, Perf BEL F5 (5150.5-5156.5), OG psi: 408, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Run in hole with run #2, (CCL/GR/GUN)(5'), Correlate, Perf BEL F5 (5141-5146), OG psi: 440, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Run in hole with run #3, (CCL/GR/GUN)(3'), Correlate, Perf BEL F2 (5117-5120), OG psi: 444, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Run in hole with run #4, (CCL/GR/GUN)(10'), Correlate, Perf BEL F2 (5082-5092), OG psi: 465, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Run in hole with run #5, (CCL/GR/GUN)(5'), Correlate, Perf BEL F2 (5062-5067), OG psi: 456, Pull out of hole.
**2" gun, 7 gr, 60 deg, 6 spf.
Rig down and release AK Eline.
API: 50-283-20195-0-000 Field: Beluga River (BRU)
Sundry #: 324-364
State: ALASKA
Rig/Service:
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A
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
3,120.00 Original KB/RT Elevation (ft):
98.10
RKB to GL (ft):
18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Surface Run Date:
6/13/2024 Set Depth (ftKB):
3,111.28
Casing Weight on Slips (1000lbf):
45,000.0 Pick Up Weight (1000lbf):
90,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
10.00 Ft/Min (ft/min):
5.19
Run Job:
241-00070 BRU 222-26 Drilling, Drilling -
Drilling, 6/5/2024 06:00
Set Depth (ftKB):
3,111.28 Set Depth (TVD) (ftKB):
2,632.5
Centralizer Detail:
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Casing Hanger 7 5/8 1.24 23.72 22.48
73 Casing Joints 7 5/8 6.87 29.70 P-110 3,002.14 3,025.86 23.72
Float Collar 8 1/2 1.32 3,027.18 3,025.86
2 Casing Joints 7 5/8 6.87 29.70 P-110 82.59 3,109.77 3,027.18
Shoe 8 1/2 1.51 3,111.28 3,109.77
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 3,111.28ftKB
Wellbore
Original Hole
Job
241-00070 BRU 222-26 Drilling, Drilling -
Drilling, 6/5/2024 06:00
Cementing Start Date
6/13/2024
Cementing End Date
6/13/2024
Top Depth (ftKB)
23.7
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
23.7
Bottom Depth (ftKB)
3,120.0
Top Measurement Method
Returns to Surface
Pump Start Date
6/13/2024
Cement in Place At
6/13/2024
Final Circulating Pressure (psi)
850.0
Plug Bump Pressure (psi)
1,315.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
95.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 1.20 10.00 60.0 4 Halliburton
Lead Slurry Lead 438 2.44 12.00 188.0 5 Halliburton
Tail Slurry Tail 174 1.16 15.80 33.0 5 Halliburton
Displacement Spud Mud 9.20 135.5 5 Halliburton
Post Job Calculations
Subtype Value
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Casing
Surface
Wellbore
Wellbore Name:
Original Hole Total Depth of Wellbore (ftKB):
3,120.00 Original KB/RT Elevation (ft):
98.10
RKB to GL (ft):
18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
Casing
Casing Description:
Surface Run Date:
6/13/2024 Set Depth (ftKB):
3,111.28
Casing Weight on Slips (1000lbf):
45,000.0 Pick Up Weight (1000lbf):
90,000.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
Parker Casing Number Hrs to Run (hr):
10.00 Ft/Min (ft/min):
5.19
Run Job:
241-00070 BRU 222-26 Drilling, Drilling -
Drilling, 6/5/2024 06:00
Set Depth (ftKB):
3,111.28 Set Depth (TVD) (ftKB):
2,632.5
Centralizer Detail:
Attribute Subtype: Value:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Float Failed?:
No
Test Subtype: Pressure (psi):
Casing (Or Liner) Details
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Casing Hanger 7 5/8 1.24 23.72 22.48
73 Casing Joints 7 5/8 6.87 29.70 P-110 3,002.14 3,025.86 23.72
Float Collar 8 1/2 1.32 3,027.18 3,025.86
2 Casing Joints 7 5/8 6.87 29.70 P-110 82.59 3,109.77 3,027.18
Shoe 8 1/2 1.51 3,111.28 3,109.77
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 3,111.28ftKB
Wellbore
Original Hole
Job
241-00070 BRU 222-26 Drilling, Drilling -
Drilling, 6/5/2024 06:00
Cementing Start Date
6/13/2024
Cementing End Date
6/13/2024
Top Depth (ftKB)
23.7
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
23.7
Bottom Depth (ftKB)
3,120.0
Top Measurement Method
Returns to Surface
Pump Start Date
6/13/2024
Cement in Place At
6/13/2024
Final Circulating Pressure (psi)
850.0
Plug Bump Pressure (psi)
1,315.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
95.0
Volume Lost (bbl)
0.0
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
Yes
Pipe Rotated?
No
Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal)
Actual Volume
Pumped (bbl)
Calculated
Volume Pumped
(bbl)Q Avg (bbl/min) Pump Used
Preflush (Spacer) Spacer 1.20 10.00 60.0 4 Halliburton
Lead Slurry Lead 438 2.44 12.00 188.0 5 Halliburton
Tail Slurry Tail 174 1.16 15.80 33.0 5 Halliburton
Displacement Spud Mud 9.20 135.5 5 Halliburton
Post Job Calculations
Subtype Value
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Casing
Siner 1
Welluore
Welluore Name:
Original Hole f otal beptT oDWelluore hDt( BK:3,120.00 ) riginal ( B/Rf OleEation hDtK:98.10
R( B to v S hDtK:18.50 ( B-Casing Glange bistance hDtK: ( B-f Luing Fanger bistance hDtK:
PBf bs
beptThDt( BK:
Casing
Casing bescription:
Liner 1 RLn bate:
6/20/2024 Het beptT hDt( BK:7,653.00
Casing WeigTt on Hlips h1000luDK:PickUpWeigTth1000luDK:95,000.0 Block WeigTt h1000luDK:15,000.0
Make-Up Contractor:
Parker Casing NLmuer Frs to RLn hTrK:15.00 Gt/Min hDt/minK:8.50
RLn Jou:
241-00070 BRU 222-26 Drilling, Drilling -
Drilling, 6/5/2024 06:00
Het beptT hDt( BK:7,653.00 Het beptT hfVbKhDt( BK:6,900.8
Centralizer betail:
AttriuLte HLutype: ValLe:
Pipe Reciprocated?:
Yes Pipe Rotated?:
No Gloat Gailed?:
No
f est HLutype: PressLre hpsiK:
Casing h) r SinerKbetails
Jts Item Des
OD Nominal
(in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make
Section Length
(ft)Btm (ftKB) Top (ftKB)
Liner Hanger 6 7/8 4.76 37.68 2,910.66 2,872.98
148 Liner 3 1/2 2.99 9.30 L-80 4,708.26 7,618.92 2,910.66
Float/Landing Collar 4 1/2 1.69 7,620.61 7,618.92
1 Liner 3 1/2 2.99 9.30 L-80 30.47 7,651.08 7,620.61
Float Shoe 4 1/2 1.92 7,653.00 7,651.08
Page 1/1
Well Name: BRU 222-26
Report Printed: 8/28/2024
www.peloton.com
Cement
Liner Cement
Type
Casing
Description
Siner Ceu ent
Ceu entef mtring
Siner d, 3,1. 28KKBtWl
beOOHore
J riginaO4oOe
-oH
07dRKKK3K l U6 000R01 DriOOing, DriOOing R
DriOOing, 1/. /0K07 K15KK
Ceu enting mtart Date
1/0d/0K07
Ceu enting : nf Date
1/0d/0K07
Top DeptEhBtWl(
0,) . K8K
Cement Stages
Stage Number: 1
Description
Siner Ceu ent
Top DeptEhBtWl(
0,) . K8K
l ottou DeptEhBtWl(
3,1. 78K
Top MeasPreu ent MetEof
Cl S
FPu p mtart Date
1/0d/0K07
Ceu ent in FOace At
1/0d/0K07
?inaOCircPOating FressPre hpsi(
d,10. 8K
FOPg l Pu p FressPre hpsi(
0,d2. 8K
?POOUetPrnY
%e s
UetPrns DPring -oHhV ( 9oOPu e to mPrBace hHHO(
.)8K
9oOPu e Sost hHHO(
)8K
lPupFOPgY
%e s
?Ooat ?aiOef Y
Lo
Fipe Ueciprocatef Y
%e s
Fipe Uotatef Y
Lo
mOPrry Type COass Au oPnt hsacNs( %ieOfhBtk/sacN( Dens hOH/gaO(
ActPaO9oOPu e
FPu pef hHHO(
CaOcPOatef
9oOPu e FPu pef
hHHO(³AQg hHHO/u in( FPu p 6sef
FreBOPsEhmpacer( mpacer TPne Friu ef 28v0 dK8.K 2K8K74aOOiHPrton
Seaf mOPrry Seaf Type OOO7.d082) d08KK dv. 8K74aOOiHPrton
TaiOmOPrry TaiO Type OOO d00 d807 d. 82K 078K74aOOiHPrton
DispOaceu ent DispOaceu en
t
)8.. 338.74aOOiHPrton
Post Job Calculations
mPHtype 9aOPe
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: 8/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240827
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 23 50133206350000 214093 7/18/2024 AK E-LINE PPROF
BRU 222-24 50283201800000 220043 8/8/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 8/6/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 8/12/2024 AK E-LINE Perf
BRU 241-34S 50283201980000 224077 8/2/2024 AK E-LINE Perf
BRU 241-34S 50283201980000 224077 7/28/2024 HALLIBURTON CAST-CBL
IRU 44-36 50283200890000 193022 8/10/2024 AK E-LINE PlugPerf
PBU 18-13D 50029217560400 224039 8/2/2024 HALLIBURTON RBT
PBU 18-33A 50029225980100 204070 8/13/2024 HALLIBURTON RBT
PBU Z-228 50029237180000 222055 7/28/2024 HALLIBURTON PPROF
PBU Z-234 50029237620000 223065 7/29/2024 HALLIBURTON IPROF
PCU 2 50283200229000 179009 7/9/2024 AK E-LINE TubingCut
TBU M-02 50733203890000 187061 8/6/2024 AK E-LINE CBL
TBU M-02 50733203890000 187061 8/12/2024 AK E-LINE Perf
Please include current contact information if different from above.
T39491
T39492
T39493
T39493
T39494
T39495
T39495
T39496
T39497
T39498
T39499
T39500
T39501
T39502
T39502
BRU 222-26 50283201950000 224035 8/6/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.08.27 11:27:22 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 8/13/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240813
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 222-24 50283201800000 22Ϭ043 8/1/2024 AK E-LINE CIBP
BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug
BRU 232-04 50283100230000 162037 7/25/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 7/24/2024 AK E-LINE CBL
BRU 241-26 50283201970000 224068 7/31/2024 AK E-LINE CBL
BRU 241-34S 50283201980000 224077 7/10/2024 AK E-LINE CBL
BRU 241-34S 50283201980000 224077 7/18/2024 AK E-LINE CBL
BRU 241-34S 50283201980000 224077 7/23/2024 AK E-LINE CBL
BRU 241-34S 50283201980000 224077 7/28/2024 AK E-LINE Hoist
IRU 44-36 50283200890000 193022 8/3/2024 AK E-LINE CBL
IRU 44-36 50283200890000 193022 7/31/2024 AK E-LINE CIBP
IRU 44-36 50283200890000 193022 7/29/2024 AK E-LINE RCT
MPU I-01 50029220650000 190090 7/20/2024 AK E-LINE CBL
MRU M-02 50733203890000 187061 7/20/2024 AK E-LINE Plug
PBU PTM P1-08A 50029223840100 202199 7/23/2024 AK E-LINE CBL
PBU V-220 50029233830000 208020 6/28/2024 READ InjectionProfileAnalysis
PTU DW-01 50089200320000 214206 7/16/2024 READ CaliperSurvey
PTU DW-0ϭ 50089200320000 214206 7/17/2024 READ TemperatureSurvey
Please include current contact information if different from above.
T39418
T39419
T39420
T39421
T39421
T39422
T39422
T39422
T39422
T39423
T39423
T39423
T39424
T39425
T39426
T39427
T39428
T39428
BRU 222-26 50283201950000 224035 7/21/2024 AK E-LINE Plug
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.08.13 13:58:22 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 7/30/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240730
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 14B 50133205390200 222057 5/22/2024
YELLOW
JACKET PERF
BCU 14B 50133205390200 222057 6/11/2024
YELLOW
JACKET GPT-PLUG-PERF
BCU 19RD 50133205790100 219188 7/17/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 7/1/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 7/11/2024 AK E-LINE PressureTemp
CLU 16 50133207200000 224021 5/16/2024
YELLOW
JACKET SCBL
CLU 16 50133207200000 224021 5/31/2024
YELLOW
JACKET SCBL
END 2-14 50029216390000 186149 5/9/2024
YELLOW
JACKET PLUG
KU 33-08 50133207180000 224008 5/9/2024
YELLOW
JACKET GPT-PLUG-PERF
MPU H-08B 5.00292E+13 201047 7/14/2024 READ CaliperSurvey
MPU I-40 50029236890000 220071 7/6/2024 AK E-LINE TubingCut
MPU R-101 50029237930000 224078 7/16/2024
YELLOW
JACKET SCBL
MPU S-17 50029231150000 202173 7/12/2024 AK E-LINE TubingCut
MPU S-17 5.00292E+13 202173 7/18/2024 READ CaliperSurvey
PBU NK-43 50029229980000 201001 6/11/2024
YELLOW
JACKET PL
PBU PTM P1-13 50029223720000 193074 7/4/2024
YELLOW
JACKET PL
Pearl 11 50133207120000 223032 7/10/2024 AK E-LINE Plug/Perf
Please include current contact information if different from above.
T39310
T39310T
T39311T
T39312T
T39312
T39313
T39313
T39314
T39315
T39316
T39317
T39318
T39319
T39319
T39320
T39321
T39322
BRU 222-26 50283201950000 224035 7/1/2024 AK E-LINE CBL
BRU 222-26 50283201950000 224035 7/11/2024 AK E-LINE PressureTemp
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.30 13:09:33 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 07/18/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-26
- PTD 224-035
- API 50-283-20195-00-00
MUDLOGS - EOW DRILLING REPORTS (06/10/2024 to 06/19/2024)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
Drilling Dynamics Log
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
224-035
T39250
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.19 08:21:31 -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:AK_GeoTech
To:Guhl, Meredith D (OGC)
Subject:Hilcorp Alaska Data Added to SFTP Site (BRU 222-26 Final Mudlogs - Samples Not Retained)
Date:Thursday, July 18, 2024 3:53:53 PM
Attachments:BRU 222-26 AOGCC FINAL MUDLOGS-EOW REPORT 19JUN2024.doc
Hello,
THE FOLLOWING DATA IS ON THE HILCORP SFTP SITE:
Note: Drilling Samples for this well were not retained at the wellsite.
BRU 222-26
PTD 224-035
API 50-283-20195-00-00
MUDLOGS - EOW DRILLING REPORTS (06/10/2024 to 06/19/2024)
If you have any questions or issues accessing the files/data, please let me know.
David DouglasGeotechnician | Hilcorp Alaska, LLCO: (907) 777-8337C: (907) 887-6339david.douglas@hilcorp.comAK_Geotech@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, 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 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.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links
or open attachments unless you recognize the sender and know the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Subject:RE: BRU 222-26 CBL (PTD 224-035)
Date:Wednesday, July 3, 2024 8:17:00 AM
Attachments:image002.png
Jake,
Hilcorp has approval to proceed with perforating per sundry 324-364.
Bryan McLellan
Senior Petroleum Engineer
Alaska Oil & Gas Conservation Commission
Bryan.mclellan@alaska.gov
+1 (907) 250-9193
From: Jacob Flora <Jake.Flora@hilcorp.com>
Sent: Wednesday, July 3, 2024 7:57 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Subject: BRU 222-26 CBL (PTD 224-035)
Hello Bryan,
Please see attached CBL for the new drill in Beluga.
Thanks,
Jake
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity
named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination,
distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if
the sender's phone number is listed above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward
transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the
company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 7/02/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 222-26
- PTD 223-035
- API 50-283-20195-00-00
FINAL LWD FORMATION EVALUATION LOGS (06/10/2024 to 06/19/2024)
ADR, DGR, PCG, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
224-035
T39104
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.02 15:10:51 -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:Justin Gruenberg - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Joshua Riley - (C)
Subject:BRU 222-26 MIT test
Date:Sunday, June 23, 2024 6:03:28 AM
Attachments:BRU 222-26 MIT-T & MIT-IA testing form.xlsx
Please find the attached MIT inspection form for BRU 222-26.
Justin Gruenberg
Hilcorp DSM – HEC 169
Office Phone (907) 283-1369
Cell Phone (907) 715-4195
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.
%HOXJD5LYHU8QLW
37'
Submit to:
OOPERATOR:
FIELDD // UNITT // PAD:
DATE:
OPERATORR REP:
AOGCCC REP:
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240350 Type Inj N Tubing 0 3080 3050 3040 Type Test P
Packer TVD 2458 BBL Pump 0.7 IA 0 20 20 20 Interval O
Test psi 3000 BBL Return 0.7 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD 2240350 Type Inj N Tubing 0 230 230 230 Type Test P
Packer TVD 2458 BBL Pump 1.4 IA 0 3240 3200 3200 Interval O
Test psi 3000 BBL Return 1.4 OA Result P
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
MMechanicall Integrityy Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Liner top packer at 2458' TVD, MIT-IA post completion 3.5" x 7.625"
Notes:
Notes:
Hilcorp Alaska LLC
Beluga / BRU 222-26
Justin Gruenberg
06/23/24
Notes:Liner top packer at 2458' TVD, MIT-T post completion 3.5" tubing and liner
Notes:
Notes:
Notes:
BRU 222-26
BRU 222-26
Form 10-426 (Revised 01/2017)2024-0623_MITP_BRU_222-26_2tests
9
9
9999
9
999
99
9
-5HJJ
MIT-T post completion
MIT-IA post completion
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, CTCO, N2
2.Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number):10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
7,654'N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 10,540psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
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
AKA029657
224-035
50-283-20195-00-00
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
~2,935
10,160psi
~2,651"
Size
120'
~3,135
MD
See Attached Schematic
2,980psi
6,890psi
120'120'
~3,135
July 4, 2024
Tieback 3-1/2"
~7,654
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 222-26CO 802
Same
~6,902'3-1/2"
~2261psi
~7,654
N/A
Length
LTP; N/A ~2,935' MD/ ~2,492' TVD; N/A, N/A
~6,902'~7,600'~6,844'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
O
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 2:54 pm, Jun 21, 2024
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2024.06.21 11:59:04 -
08'00'
Noel Nocas
(4361)
324-364
A.Dewhurst 24JUN24
BJM 6/24/24
10-407
DSR-6/25/24
CT BOP test to 2500 psi.
Submit CBL to AOGCC and obtain approval before perforating.
X
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.06.26 12:34:22 -08'00'06/26/24
RBDMS JSB 062624
Well Prognosis
Well Name: BRU 222-26 API Number: 50-283-20195-00-00
Current Status: Gas Producer Permit to Drill Number: 224-035
First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C)
Second Call Engineer: Chad Helgeson (907) 229-4824 (C)
Maximum Expected BHP: 2925 psi @ 6648’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2261 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 222-26 is the first of five grass roots wells drilled in the 2024 drilling campaign targeting the Sterling and
Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen, complete a CBL and
perforate multiple Beluga sands. All sands lie in the Sterling Beluga Gas Pool.
Wellbore Conditions:
Drilling will leave the cemented 3.5” liner full of drilling mud, with the 3.5” tubing and annulus displaced to KCL,
and pressure tested.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 2500 psi.
4. Clean out wellbore to PBTD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, PT lubricator to 2500psi, log CBL submit CBL to AOGCC for review
6. RIH, reverse out wellbore with nitrogen, trap ~1700 psi on wellbore
7. RDMO coil tubing
8. RU E-line, PT lubricator to 2500 psi
9. Perforate and test Beluga sands within the interval below, from the bottom up:
Pool Top (Sterling A1) 3764’ MD 3143’ TVD
Planned Interval (Beluga D – J) 4415’ – 7399’ MD 3693’ – 6648’ TVD
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 13.89 ppg EMW FIT at the surface casing shoe (0.722 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.722-0.1) = 2261 psi / 0.622 = 3635‘ TVD
10. RDMO
11. Turn well over to production & flow test well
Well Prognosis
Contingencies:
Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating):
1. MIRU Coiled Tubing, notify AOGCC 48 hours in advance of BOP test, PT BOPE to 2500 psi
2. Clean out to TD (or desired depth by engineer)
3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU
Attachments:
1. Current Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
Updated by DMA 06-20-24
CURRENT SCHEMATIC
Beluga River Unit
BRU 222-26
PTD: 224-035
API: 50-283-20195-00-00
PBTD = ±7,600’ / TVD = ±6,844’
TD = 7,654’ / TVD = ±6,902’
RKB to GL = 18.5’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf ±3,135’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” ±2,935’ ±7,654’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf ±2,935’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ±1,500 2.813” 3.500” Chemical Injection Sub
2 ±2,935’ 4.875” 6.540” Liner hanger / LTP Assembly
3 ±2,935’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (75% / 50% Lead/Tail excess)
3-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
1
Updated by DMA 06-20-24
PROPOSED SCHEMATIC
Beluga River Unit
BRU 222-26
PTD: 224-035
API: 50-283-20195-00-00
PBTD = ±7,600’ / TVD = ±6,844’
TD = 7,654’ / TVD = ±6,902’
RKB to GL = 18.5’
CASING DETAIL
Size Type Wt Grade Conn. ID Top Btm
16” Conductor – Driven
to Set Depth 84 X-56 Weld 15.01” Surf 120’
7-5/8" Surf Csg 29.7 L-80 GBCD 6.875” Surf ±3,135’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” ±2,935’ ±7,654’
3-1/2" Prod Tieback 9.2 L-80 EUE 2.992” Surf ±2,935’
3
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 ±1,500 2.813” 3.500” Chemical Injection Sub
2 ±2,935’ 4.875” 6.540” Liner hanger / LTP Assembly
3 ±2,935’ 4.790” 6.340” Seal Stem
OPEN HOLE / CEMENT DETAIL
7-5/8" Est. TOC @ Surface (75% / 50% Lead/Tail excess)
3-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
1
PERFORATION DETAIL
Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments
Pool Top Sterling A1 - 3,764’ MD / 3,143’ TVD
Beluga D-J ±4,415’ ±7,399’ ±3,693’ ±6,648’ Proposed TBD
STANDARD WELL PROCEDURE
NITROGEN OPERATIONS
12/08/2015 FINAL v1 Page 1 of 1
1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport.
2.) Notify Pad Operator of upcoming Nitrogen operations.
3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and
appropriate Safety Data Sheets (formerly MSDS).
4.) Document hazards and mitigation measures and confirm flow paths. Include review on
asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate
routing of flowlines, adequate venting and atmospheric monitoring.
5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport.
6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip
checks.
7.) Place signs and placards warning of high pressure and nitrogen operations at areas where
Nitrogen may accumulate or be released.
8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing
and casing pressures.
9.) Place pressure gauges upstream and downstream of any check valves.
10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct.
11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to
detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as
well that measures O2 levels.
12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential
Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)
to 1,500 psi. Perform visual inspection for any leaks.
13.) Bleed off test pressure and prepare for pumping nitrogen.
14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns
are to be routed to the returns tank.
15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and
bleed down lines between well and Nitrogen Pumping Unit.
16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has
accumulated begin rig down of lines from the Nitrogen Pumping Unit.
17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned
and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport.
18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 222-26
JBR 07/24/2024
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:3
4-1/2" joint. Annular FP-cycle & adjust pressure for a pass. BOP misc FP-kill line flange-tighten for a pass. Lower rams FP-cycle
for a pass.
Test Results
TEST DATA
Rig Rep:Ken PorterfieldOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley
Rig Owner/Rig No.:Hilcorp 147 PTD#:2240350 DATE:6/14/2024
Type Operation:DRILL Annular:
250/5000Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopSAM240617233941
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7.5
MASP:
2435
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
13 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 11"FP
#1 Rams 1 2-7/8"x5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"FP
#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/P
Kill Line Valves 3 2-1/16"P
Check Valve 0 NA
BOP Misc 1 Flange FP
System Pressure P3050
Pressure After Closure P1750
200 PSI Attained P24
Full Pressure Attained P90
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2650
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P12
#1 Rams P4
#2 Rams P4
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9
9999
9
9
9
9
FP
FP
FP
Annular FP BOP misc FP Lower rams FP-
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: Beluga River Unit Field, Sterling-Beluga Gas Pool, BRU 222-26
Hilcorp Alaska, LLC
Permit to Drill Number: 224-035
Surface Location: 815' FSL, 765' FWL, Sec 26, T13N, R10W, SM, AK
Bottomhole Location: 2471' FNL, 2488' FWL, Sec 26, T13N, R10W, 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 May 2024. 20th
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: 7,654' TVD: 6,898'
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): 98.1 15. Distance to Nearest Well Open
Surface: x-318704 y- 2625965 Zone-4 79.6 to Same Pool: 1371' to BRU 214-26
16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 39 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 GBCD 3,135' Surface Surface 3,135' 2,651'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,719' 2,935' 2,495' 7,654' 6,898'
Tieback 3-1/2" 9.2# L-80 EUE 2,935' Surface Surface 2,935 2,495'
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
BRU 222-26
Beluga River Unit
Sterling-Beluga 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 - 1061 ft3 / T - 131 ft3
2435
2168' FSL, 1928' FWL, Sec 26, T13N, R10W, SM, AK
2471' FNL, 2488' FWL, Sec 26, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
815' FSL, 765' FWL, Sec 26, T13N, R10W, SM, AK AKA029657
18. Casing Program: Top - Setting Depth - BottomSpecifications
3125
GL / BF Elevation above MSL (ft):
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 1055 ft3 / T - 162 ft3
Effect. Depth MD (ft): Effect. Depth TVD (ft):
LengthCasing
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
Production
Liner
Intermediate
Drilling Manager
Monty Myers
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
5/25/2024
4374' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
Tieback Assy.
1474
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
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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)
Drilling Manager
04/16/24
Monty M
Myers
By Grace Christianson at 10:28 am, Apr 16, 2024
224-035
BJM 5/17/24 DSR-4/23/24
Initial BOP test to 5000 psi, subsequent BOP tests to 3000 psi
all annular tests to 2500 psi.
50-283-20195-00-00
SFD 5/3/2024
Submit FIT/LOT data with 48 hrs of performing test.
BRU 222-26
PTD Program
Beluga River Unit
April 9, 2024
BRU 222-26
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 9-7/8 Hole Section..............................................................................................................13
12.0 Run 7-5/8 Surface Casing ..........................................................................................................15
13.0 Cement 7-5/8 Surface Casing ....................................................................................................17
14.0 BOP N/U and Test........................................................................................................................20
15.0 Drill 6-3/4 Hole Section..............................................................................................................21
16.0 Run 3-1/2 Production Liner ......................................................................................................23
17.0 Cement 3-1/2 Production Liner ................................................................................................26
18.0 3-1/2 Liner Tieback Polish Run ................................................................................................30
19.0 3-1/2 Tieback Run, ND/NU, RDMO.........................................................................................31
20.0 Diverter Schematic ......................................................................................................................32
21.0 BOP Schematic.............................................................................................................................33
22.0 Wellhead Schematic.....................................................................................................................34
23.0 Anticipated Drilling Hazards......................................................................................................35
24.0 Hilcorp Rig 147 Layout...............................................................................................................37
25.0 FIT/LOT Procedure ....................................................................................................................38
26.0 Choke Manifold Schematic.........................................................................................................39
27.0 Casing Design Information.........................................................................................................40
28.0 6-3/4 Hole Section MASP ..........................................................................................................41
29.0 Spider Plot w/ 660 Radius for SSSV .........................................................................................42
30.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................43
Page 2 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
1.0 Well Summary
Well BRU 222-26
Pad & Old Well Designation BRU H Pad Grassroots Well
Planned Completion Type 3-1/2Production Liner w/Tieback (monobore)
Target Reservoir(s) Sterling/Beluga
Planned Well TD, MD / TVD 7654 MD / 6898 TVD
PBTD, MD / TVD 7554 MD / 6798TVD
AFE Number
AFE Drilling Days 25
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface) 2435 psi
Maximum Anticipated Pressure
(Downhole/Reservoir) 3125 psi
Work String 4-1/2 16.6# S-135 CDS-40
RKB 98.1
Ground Elevation 79.6
BOP Equipment 11 5M Annular BOP
11 5M Double Ram
11 5M Single Ram
Page 3 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
2.0 Management of Change Information
Page 4 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
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 1615.01 14.822- 84 X-56 Weld 2980 1410 -
Surface
9-7/87-5/8 6.875 6.750 8.50029.7 L-80 GBCD 6890 4790 683
Prod
6-3/43-1/22.9922.8674.2509.2 L-80 HYD-563 10160 10540 207
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 4-1/23.826 2.6875 5.2516.6 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 PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
Report covers operations from 6am to 6am
Ensure time entry adds up to 24 hours total.
Capture any out-of-scope work as NPT.
5.2 Afternoon Updates
Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
Submit a short operations update each morning by 7am in NDE Drilling Comments
5.4 EHS Incident Reporting
Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, dont wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills:
Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final As-Run Casing tally to Sean.McLaughlin@hilcorp.com, and cdinger@hilcorp.com
5.6 Casing and Cmt report
Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com, and
cdinger@hilcorp.com
Page 6 Version PTD April 9, 2024
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Drilling Procedure
PTD
6.0 Planned Wellbore Schematic
Page 7 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
7.0 Drilling / Completion Summary
BRU 222-26 is an S-shaped directional grassroots development well to be drilled from BRU H Pad.
Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the
Sterling and Beluga sands.
The base plan is an S-shaped directional wellbore with a kickoff point at ~250MD. Maximum hole angle
will be ~39 deg. and TD of the well will be 7654 TMD/ 6898 TVD, ending with 6 deg inclination left in
the hole. Vertical separation will be 2631 ft.
Drilling operations are expected to commence approximately May, 2024. The Hilcorp Rig # 147 will be used
to drill the wellbore then run casing and cement.
Surface casing will be run to 3135MD / 2,651 TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example) maybe run to determine
TOC. Necessary remedial action will then be discussed with BLM and AOGCC authorities.
All waste & mud generated during drilling and completion operations will be hauled to the Beluga Waste
Cells. The contingency plan will be tohaul cuttingsto the Kenai Gas Field G&I facility for disposal / beneficial
reuse depending on test results.
General sequence of operations:
1. MOB Hilcorp Rig # 147 to wellsite
2. N/U diverter and test.
3. Drill 9-7/8hole to 3135 MD. Run and cmt 7-5/8surface casing.
4. ND diverter, N/U & test 11 x 5M BOP.
5. Drill 6-3/4 hole section to 7654MD. Perform Wiper trip.
6. Make cleanout run
7. Run and cmt 3-1/2production liner.
8. Displace well to 6% KCL completion fluid.
9. POOH and LDDP.
10. RIH and land 3-1/2 tieback string in liner top.
11. Test IA to 2500; Test tubing to 2500 psi
12. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo
Page 8 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
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.
BOPs shall be tested at (2) week intervals during the drilling of BRU 222-26. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing.
The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
All AOGCC regulations within 20 AAC 25.033 Primary well control for drilling: drilling fluid
program and drilling fluid system.
All AOGCC regulations within 20 AAC 25.035 Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements
Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man
office.
Review all conditions of approval of the BLM APD and the AOGCC PTD on the 10-401 form.
Ensure that the conditions of approval are captured in shift handover notes until they are executed
and complied with.
BLM Regulation Variance Requests:
Onshore Oil and Gas Order No. 1, Section III. D. 3. C.
o 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 Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping.
5000 psi - bjm
Page 9 Version PTD April 9, 2024
BRU 222-26
Drilling Procedure
PTD
Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/821-1/4 x 2M Hydril MSP diverter Function Test Only
6-3/4
11 x 5M Annular BOP
11 x 5M Double Ram
o Blind ram in btm cavity
Mud cross
11 x 5M Single Ram
3-1/8 5M Choke Line
2-1/16 x 5M Kill line
3-1/8 x 2-1/16 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3000
(Annular 2500 psi)
Subsequent Tests:
250/3000
(Annular 2500 psi)
Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
48 hours notice prior to testing BOPs.
Any other notifications required in APD.
Required BLM Notifications:
48 hours before spud. Follow up with actual spud date and time within 24 hours.
72 hours before casing running and cmt operations
72 hours before BOPE tests
72 hours before logging, coring, & testing
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
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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 landing ring on conductor.
9.4 Level pad and ensure enough room for layout of rig footprint and R/U.
9.5 Layout Herculite on pad to extend beyond footprint of rig.
9.6 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.8 Mix mud for 9-7/8hole section.
9.9 Install 5-1/2 liners in mud pumps.
HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2 liners.
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10.0 N/U 21-1/4 2M Diverter
10.1 N/U 21-1/4 Hydril MSP 2M diverter System.
N/U 16-3/4 3M x 21-1/4 2M DSA (Hilcorp) on 16-3/4 3M wellhead.
N/U 21-1/4 diverter T.
Knife gate, 16 diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
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:
A prohibition on vehicle parking.
A prohibition on ignition sources or running equipment.
A prohibition on staged equipment or materials.
Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
10.5 Rig 147 and estimated Diverter line orientation on BRU H Pad:
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11.0 Drill 9-7/8Hole Section
11.1 P/U 9-7/8directional drilling assy:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Workstring will be 4.5 16.6# S-135 CDS40
11.2 4-1/2Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8hole section to 3135MD/ 2,651 TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
Utilize Inlet experience to drill through coal seams efficiently.
Keep swab and surge pressures low when tripping.
Make wiper trips every 1000 or every couple days unless hole conditions dictate otherwise.
Ensure shale shakers are functioning properly. Check for holes in screens on connections.
Adjust MW as necessary to maintain hole stability.
TD the hole section in a good shale
Take MWD surveys every stand drilled (60 intervals).
11.5 9-7/8hole 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 drillers console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 8.8 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-3135 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 16conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 7-5/8casing running equipment.
Ensure 7-5/8TXP x CDS 40 XO on rig floor and M/U to FOSV.
R/U fill-up line to fill casing while running.
Ensure all casing has been drifted on the location prior to running.
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
(1) Shoe joint w/ float shoe bucked on (thread locked).
(1) Joint with coupling thread locked.
(1) Joint with float collar bucked on pin end & thread locked.
Install (2) centralizers on shoe joint over a stop collar. 10 from each end.
Install (1) centralizer, mid tube on thread locked joint and on FC joint.
Ensure proper operation of float equipment.
12.5 Continue running 7-5/8surface casing
Fill casing while running using fill up line on rig floor.
Use API Modified thread compound. Dope pin end only w/ paint brush.
Install (1) centralizer every other joint to 300. Do not run any centralizers above 300 in the
event a top out job is needed.
Utilize a collar clamp until weight is sufficient to keep slips set properly.
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 7-5/8Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
Pump 20 bbls of freshwater through all of Halliburtons equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
How to handle cmt returns at surface.
Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% lead open hole excess. Job will consist of lead
& tail, TOC brought to surface.
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Estimated Total Cement Volume:
Cement Slurry Design:
Lead Slurry (2635 MD to surface)Tail Slurry (3135 to 2635 MD)
System Extended Conventional
Density 12 lb/gal 15.8 lb/gal
Yield 2.44 ft3/sk 1.16 ft3/sk
Mixed Water 14.40 gal/sk 5.03 gal/sk
Mixed Fluid 14.40 gal/sk 5.03 gal/sk
Additives
Code Description Code Description
Type I/II Cement Class A Type I/II Cement Class A
CalSeal Accelerator D-Air 5000 Anti Foam
VersaSet Thixotropic Calcium Chloride Accelerator
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner
BridgeMaker II Lost Circulation
Verified cement calcs -bjm
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13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets sticky, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls.
Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 18 hours after CIP.
Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require running steel pipe through the hanger flutes. The ID of the flutes is
1.5.
13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.14 R/D cement equipment. Flush out wellhead with FW.
13.15 Back out and L/D landing joint. Flush out wellhead with FW.
13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.17 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
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Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final As-Run casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
14.0 BOP N/U and Test
14.1 ND Diverter line and diverter
14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test
Packoff to 3000 psi.
14.3 N/U 11 x 5M BOP as follows:
BOP configuration from Top down: 11 x 5M annular BOP/11 x 5M double ram /11 x 5M
mud cross/11 x 5M single ram
Double ram should be dressed with 2-7/8 x 5 variable bore rams in top cavity, blind ram
in btm cavity.
Single ram should be dressed with 2-7/8 x 5 variable bore rams
N/U bell nipple, install flowline.
Install (2) manual valves & a check valve on kill side of mud cross.
Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Land out test plug (if not installed previously).
Test BOP to 250/3000 psi for 5/10 min.
Test VBRs with 3-1/2and 4-1/2test joints
Test annular to 250/2500 psi for 10/10 min with a 3-1/2 test joint
Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 Rack back as much 4-1/2DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 6-3/4 Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly.
15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software.
15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
15.7 Workstring will be 4.5 16.6# S-135 CDS40. Ensure to have enough 4-1/2 DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4 hole section mud program summary:
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 drillers console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
3135- 76549.0 10.0 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4 directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8 L-80 burst is 6880 psi / 2 = 3440 psi.
15.11 Drill out shoe track and 20 of new formation.
15.12 CBU and condition mud for FIT.
15.13 Conduct FIT to 14.0 ppg EMW. A 13.6# ppg FIT will result in a 25 bbl KTV.
15.14 Drill 6-3/4 hole section to 7654 MD / 6898 TVD
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
Keep swab and surge pressures low when tripping.
Make wiper trips every 1000 unless hole conditions dictate otherwise.
Trip back to the 7-5/8 shoe about ½ way through the hole section
Ensure shale shakers are functioning properly. Check for holes in screens on connections.
Lost circulation potential when drilling through Beluga D and E (4392 -4988 MD).
Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
Take MWD surveys every 100drilled. Surveys can be taken more frequently if deemed
necessary.
15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RIH to TD, pump sweep, CBU and condition mud for casing run.
Test casing to 3500 psi. -bjm
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15.19 POOH LDDP and BHA
15.20 2-7/8 x 5 VBRs previously installed in BOP stack and tested with 3-1/2 test joint.
16.0 Run 3-1/2Production Liner
16.1. R/U Parker 3-1/2casing running equipment.
Ensure 3-1/2HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
R/U fill up line to fill casing while running.
Ensure all casing has been drifted prior to running.
Be sure to count the total # of joints before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
(1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
(1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
(1) Joint with Baker landing collar bucked on pin end & threadlocked.
Solid body centralizers will be pre-installed on shoe joint an FC joint.
Leave centralizers free floating so that they can slide up and down the joint.
Ensure proper operation of float shoe and float collar.
Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2production liner
Fill casing while running using fill up line on rig floor.
Use API Modified thread compound. Dope pin end only w/ paint brush.
Install solid body centralizers on every joint to the 7-5/8 shoe. Leave the centralizers free
floating.
16.5. Continue running 3-1/2 production liner
7
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16.6. Run in hole w/ 3-1/2 liner to the 7-5/8 casing shoe.
16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole
dictates.
16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing.
16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe.
16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid
surging the hole. Slow down running speed if necessary.
16.11. Set casing slowly in and out of slips.
16.12. PU 3-1/2 X 7-5/8 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 3-1/2Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
Pump 20 bbls of freshwater through all of Halliburtons equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
Positions and expectations of personnel involved with the cmt operation.
Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
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Estimated Total Cement Volume:
Cement Slurry Design:
Lead Slurry (7154 MD to 2935 MD)Tail Slurry (7654 to 7154 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 Code Description
Type I/II Cement Class A Type I/II Cement Class A
Halad-344 Fluid Loss Halad-344 Fluid Loss
HR-5 Retarder HR-5 Retarder
D-Air 5000 Anti Foam CFR-3 Dispersant
Econolite Light-weight add. FDP-C1446-21 Slurry Conditioner
SA-1015 Suspension Agent
BridgeMaker II Lost Circulation
Verified cement calcs. -bjm
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17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow continue rotating
and reciprocating liner throughout displacement. This will ensure a high quality cement job with
100% coverage around the pipe.
17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP
entering into liner.
17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by 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 0.7 bbls.
17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in
compression.
17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from
the liner.
17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as reqd 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.
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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 3000 psi and chart for 30 minutes.
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Ensure to report the following on wellez:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final As-Run casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 3-1/2Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, and LDDP and polish mill.
18.4. If not completed, test 3-1/2 casing to 3000 psi and chart for 30 minutes
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19.0 3-1/2 Tieback Run, ND/NU, RDMO
19.1 PU 3-1/2 tieback assembly and RIH with 3-1/2 9.2# L-80 EUE. Ensure any jewelry is picked
up per tally.
Install chemical injection mandrel at ~1,500 MD.
19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space
out tieback seals in PBR.
19.3 Circulate inhibited completion fluid.
19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance
of seals from no-go.
19.5 Install packoff and test hanger void.
19.6 Test 3-1/2 liner and tieback to 3000 psi and chart for 30 minutes. 48 hr notice required.
19.7 Test 7-5/8 x 3-1/2 annulus to 3000 psi and chart for 30 minutes. 48 hr notice required.
19.8 Install BPV in wellhead
19.9 N/D BOPE
19.10 N/U dry-hole tree and test
19.11 RDMO Hilcorp Rig #147
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20.0 Diverter Schematic
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21.0 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Anticipated Drilling Hazards
9-7/8Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200 of drilling to
reduce the likelihood of washing out the conductor shoe.
To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4 Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
Use asphalt-type additives to further stabilize coal seams.
Increase fluid density as required to control running coals.
Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
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24.0 Hilcorp Rig 147 Layout
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25.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
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26.0 Choke Manifold Schematic
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27.0 Casing Design Information
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28.0 6-3/4 Hole Section MASP
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29.0 Spider Plot w/ 660 Radius for SSSV
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30.0 Surface Plat (As-Built NAD27 & NAD83)
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
Beluga River Unit
BRU 222-26
224-035
Sterling-Beluga Gas
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 222-26Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240350BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes Entire Well lies within ADL0029657.2 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, Sterling-Beluga Gas Pool 92500, governed by CO 802, issued May 5, 20224 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes BOP rating = 5 kpsi, MPSP = 2435 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes None expected based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Well will encounter normally pressured and severely underpressured strata.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/3/2024ApprBJMDate5/17/2024ApprSFDDate5/3/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate
