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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: 3/14/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240314
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 13 50133205250000 203138 1/20/2024 AK E-LINE GPT/PL
BCU 13 50133205250000 203138 1/4/2023 AK E-LINE JetCut/CBL
BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf
HV B-13 50231200320000 207151 12/22/2023 AK E-LINE CBL
IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf
KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf
KTU 32-07H 50133205110000 202043 10/27/2023 AK E-LINE PPROF
KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL
KU 21X-32 50133202040000 169100 12/8/2023 AK E-LINE JetCut
MPU CFP-02 50029212580000 184242 3/9/2024 READ CaliperSurvey
NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT
NIA NK-18 50029224210000 193177 12/13/2023 AK E-LINE IPROF
PTM P1-13 50029223720000 193074 12/9/2023 AK E-LINE Cement
TBU M-11 50733205900000 210145 1/8/2024 AK E-LINE Perf
TBU M-15 50733204220000 190109 2/7/2024 AK E-LINE GPT/Perf
Please include current contact information if different from above.
T38615
T38615
T38616
T38617
T38618
T38619
T38620
T38621
T38622
T38623
T38624
T38625
T38626
T38627
T38628
BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.03.15 11:38:35 -08'00'
H lr+irp.Alamka, ILL
Date: 01/25/2024
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 CenterPoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 221-35
- PTD 223-077
- API 50-283-20193-00-00
Washed and Dried Well Samples (10/23/2023)
B Set (3 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 221-35
BOX 1 OF 3
2790' - 4440' MD
BRU 221-35
BOX 2 OF 3
4440' - 6030' MD
BRU 221-35
BOX 3 OF 3
6030' — 7244' MD
Please include current contact information if different from above.
Please acknowledge receipt by signing and returning one copy of this transmittal.
'9�23-0-7-7-
1 (6-TI
RECEIVED
JAN 2 5 2024
AOGCC
rceceivea ts� / I nJ� _ Date: �� +�� L 21 Z � 7-Z�.
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240112
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
END 1-27 50029216930000 187009 11/16/2023 YELLOWJACKET PERF
KALOTSA 4 50133206650000 217063 9/28/2023 YELLOWJACKET PERF
KALOTSA 8 50133207050000 222003 11/29/2023 YELLOWJACKET PERF
KBU 13-8 50133203040000 177029 11/5/2023 YELLOWJACKET PERF
KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT
KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF
KBU 11-08Z 50133206290000 214044 8/24/2023 AK E-LINE GPT/CIBP/PERF
KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL
KBU 23-05 50133206300000 214061 10/10/2023 AK E-LINE PLT
KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/PERF
MPU I-01 50029220650000 190090 11/18/2023 YELLOWJACKET PERF
PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF
PAXTON 7 50133206430000 214130 9/18/2023 YELLOWJACKET CBL
PAXTON 7 50133206430000 214130 10/7/2023 YELLOWJACKET PERF
SRU 224-10 50133101380100 222124 12/27/2023 YELLOWJACKET GPT-PLUG-PERF
SRU 224-10 50133101380100 222124 11/4/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT
SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF
SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT
SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF
SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL
Please include current contact information if different from above.
T38273
T38275
T38277
T38278
T38279
T38280
T38280
T38281
T38282
T38283
T38284
T38285
T38286
T38287
T38287
T38288
T38288
T38289
T38289
T38289
T38290
T38290
1/18/2024
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.01.18
11:52:00 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 12/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20231221
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
MPU L-47 50029235500000 215117 12/10/2023 READ Caliper Survey
Please include current contact information if different from above.
T38247
T38248
12/29/2023
BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.12.29
12:42:52 -09'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Beluga River Field
GL: 79.3' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" L-80 120'
7-5/8" L-80 2,636'
3-1/2" L-80 6,904'
3-1/2" L-80 2,564'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
N/A
SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,651' 7,244'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy.Tieback
TUBING RECORD
L - 448 sx / T - 122 sx6-3/4"
9-7/8"
Driven
Surface L - 397 sx / T - 173 sx
9.2#
Surface
Surface
2,851'
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
318582 2626002
50-283-20193-00-00October 13, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
11/18/2023 223-077 / 323-587
N/A
BRU 221-35October 23, 2023851' FSL, 642' FWL, Sec 26, T13N, R10W, SM, AK
97.8'
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2624866
SETTING DEPTH TVD
2624608
TOP HOLE SIZE
CBL 11-3-23, Mudlogs, LWD (AGR, PCG, ADR, CTN, ALD, PWD, DDSR), Tie In/Perf Logs
Sterling - Beluga Gas Pool
AKA029657
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
319532
319884
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
Conductor
N/A
N/A
N/A
7,244' MD / 6,904' TVD
7,175' MD / 6,835' TVD
263' FNL, 1605' FWL, Sec 35, T13N, R10W, SM, AK
516' FNL, 1961' FWL, Sec 35, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
9.2#
2,656'
2,560'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
11/19/2023
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
04.2442 0
12/1/2023 24
Flow Tubing
4.2
3316
N/A33160
WINJ
SPLUG Other Abandoned Suspended
Stratigraphic Test
No
No
(attached) No
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 3:01 pm, Dec 18, 2023
Completed
11/18/2023
JSB
RBDMS JSB 010324
GDSR-1/29/24
BRU 221-35
223-077 / 323-587
WCB 1-27-2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
N/A N/A
Top of Productive Interval Bel F4 4,632' 4,329'
3619' 3337'
3982' 3691'
4196' 3902'
4562' 4261'
5081' 4772'
5452' 5139'
6181' 5856'
6754' 6421'
7171' 6832'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Bel F
ST B1
Bel G
Bel J
Bel D
Bel E
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 H
Bel I
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
12/18/23
Monty M
Myers
Updated by CJD 12-18-2023
Current SCHEMATIC
Beluga River Unit
BRU 221-35
PTD: 223-077
API: 50-283-20193-00-00
PBTD = 7,175’ / TVD = 6,835’
TD = 7,244’ / TVD = 6,904’
RKB to GL = 18.5’
PERFORATION DETAIL
Sands Top MD Btm MD Top TVD Btm TVD Date Status
F4 4,632’ 4,638’ 4,329’ 4,335’ 11/21/23 Open
F4 4,647’ 4,652’ 4,344’ 4,359’ 11/21/23 Open
F4 4,666’ 4,668’ 4,363’ 4,365’ 11/21/23 Open
F5 4,714’ 4,717’ 4,411’ 4,414’ 11/21/23 Open
F5 4,728’ 4,733’ 4,425’ 4,430’ 11/21/23 Open
F5 4,735’ 4,743’ 4,432’ 4,440’ 11/21/23 Open
F6 4,792’ 4,798’ 4,487’ 4,493’ 11/21/23 Open
F6 4,810’ 4,813’ 4,499’ 4,502’ 11/21/23 Open
F6 4,842’ 4,848’ 4,537’ 4,543’ 11/21/23 Open
F7 4,855’ 4,859’ 4,550’ 4,554’ 11/21/23 Open
F7 4,868’ 4,878’ 4,563’ 4,573’ 11/20/23 Open
F7 4,928’ 4,933’ 4,621’ 4,626’ 11/20/23 Open
F7 4,946’ 4,950’ 4,639’ 4,643’ 11/20/23 Open
F10 5,021’ 5,026’ 4,713’ 4,718’ 11/20/23 Open
F10 5,030’ 5,033’ 4,722’ 4,725’ 11/20/23 Open
F10 5,041’ 5,044’ 4,733’ 4,736’ 11/20/23 Open
F10 5,050’ 5,054’ 4,742’ 4,746’ 11/20/23 Open
F10 5,060’ 5,074’ 4,751’ 4,765’ 11/20/23 Open
G1 5,101’ 5,116’ 4,792’ 4,807’ 11/20/23 Open
G2 5,129’ 5,134’ 4,820’ 4,825’ 11/19/23 Open
G2 5,160’ 5,169’ 4,850’ 4,859’ 11/19/23 Open
H1 5,516’ 5,522’ 5,201’ 5,207’ 11/18/23 Open
H4 5,619’ 5,629’ 5,302’ 5,312’ 11/18/23 Open
H13 6,031’ 6,041’ 5,709’ 5,719’ 11/18/23 Open
I12 6,712’ 6,726’ 5,379’ 5,393’ 11/18/23 Open
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 TXP 6.875” Surf 2,851’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,651’ 7,244’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,656’
1
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,651’ 4.875” 6.540” Liner hanger / LTP Assembly
2 2,656’ 4.790” 6.340” Seal Stem
3 1,510’ 2.813” 3.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface L – 397 sx / T – 173 sx
3-1/2” TOC CBL @ ~2,651’ MD L – 448 sx / T – 122 sx
6-3/4”
hole
2
3
Page 1/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:10/11/2023 End Date:11/8/2023
Report Number
1
Report Start Date
10/11/2023
Report End Date
10/12/2023
Operation
Disconnect all modules in back yard. Bed trucks clear back yard & stage modules on side of pad. Hang blocks, Service loop, Kell y Hose & Drilling line in derrick. PJSM
lay over mast to headache rack & disconnect lifting rams. Cranes remove derrick from
Draworks skid & place on trailer. Remove drilling line spool & place on same trailer. Bed truck moves Water Tank/ Accummulator? Doghouse module to side of location.
Cranes attach to Draworks skid & lift off of sub-base & place on liner.
Pick up remaining matts, Liner & Felt. Stack matts with other matts on side of location. Vacuum rainwater from liner with vac t ruck. Dispose of liner & felt. Three Mile
grader levels pad for footprint of rig & compact pad. Set Felt, Liner & Matts.
Bed truck moves Draworks skid to side of location. Cranes attach to sub-base & lift off of pony subs. Set sub-base on liner. Be tty White bed truck tail rolls sub-base &
moves to side of location. Remove pony subs with forklift & set on side of location.
Place starting head with Tee on well. Set Pony subs.
Spot in cranes and set sub over well and center, se draw works and derrick on sub, spot in water tank doghouse, scope dog house , set pit module and jig spot in mud
pumps and remaining pit modules, set gen house and boiler, set HPU and C can.
Rig up water and steam an get it going around rig, continue rigging up modules prep mast, raise and pin, lower derrick board and prep derrick to scope, lay felt and liner f/
skate, continue hooking up rig systems, hook up drive line and break linkage, hook up pason system.
Report Number
2
Report Start Date
10/12/2023
Report End Date
10/13/2023
Operation
Spool up drilling line on draworks drum & slip on 5 wraps. Set Catwalk, Gas Buster, Third party shacks & Upright water tank. Installed turnbuckles on upper torque tube,
Install steam traps in steam heaters, Cont. R/U Pits, R/U Centrifuge, Connected skate
controls from rig floor to catwalk, Connected bleeder on rig floor, Hung tarps around rig floor, Installed windwalls with crane , R/U weight indicator, Top drive torque gauge
& Pump pressure gauge. Plugged in Shaker & Mud pump cameras.
Raise mast with blocks on bridle lines. R/D bridle lines & secure. Fasten torque tube with turnbuckles & straighten same. Pick up Top Drive and connect to blocks, P/U &
install torque bushing on torque tube. Connect Top Drive to torque bushing.
Change out 37 pin connection in derrick hook up service loop and kelly hose, R/U tongs and bails on top drive, M/U saver sub and clamp, function test top drive, remove
shipping beams in cellar, work on rig acceptance checklist, bring up crossovers and handling subs to floor.
Make up bell nipple and riser install knife valve and vent line and stands, 109' over all 86' from nearest ignition source, che ck pre charge on accumulator bottles.
Report Number
3
Report Start Date
10/13/2023
Report End Date
10/14/2023
Operation
Complete rig acceptance checklist, Shimmed derrick, Pressure test Hi-Pressure lines, Function test the diverter, Chained off Di verter stack in cellar, Install 4" Ball valves
on conductor, Calibrate & Test Gas Alarms, Start building Spud Mud. Confirm all debris
picked up throughout location & rig footprint. P/U & stand back 13 stands of 4-1/2" drill pipe. Rig accepted at 12:00pm.
Continue P/U & stand back 27 stands of 4-1/2" drill pipe. P/U & stand back 17 jts of 4-1/2" HWDP & Jar.
Perform Accumulator Drawdown test with 4-1/2" drill pipe. 21-1/4" Annular Preventer closed in 37 seconds. Knife Valve opened in 25 seconds. Function test PVT visual &
audio alarms & Flow Monitor Alarms. Quadco rep calibrated & tested visual & audio gas alarms.
RIH & tag conducter fill for confirmation of room for BHA #1 Smart Tools. Tagged at 123' circulated & confirmed all systems on surface holding as designed. POOH &
install mousehole.
P/U & M/U Directional M5 BHA #1 9-7/8" Kymera Bit, 6-3/4" TerraForce Lobe Motor, DM Collar, EWR-M5 Collar & TM HOC & Download Data.
Drill 9 7/8'' Surface hole f/ 123' t/ 500' 390 gpm 846 psi SPP 30 rpm 3.1k tq on bottom, 2-5k WOB, PUW 32k SOW 24k ROT 24k.
Continue Drilling 9 7/8'' Surface hole f/ 500' t/ 1130' 405 gpm 959 psi SPP 45 rpm 3.1k tq on bottom, 3-10k WOB, PUW 32k SOW 30k ROT 32k, MW 8.9 ppg Distance to
plan 2.16' .37' Low 2.13' Right.
Report Number
4
Report Start Date
10/14/2023
Report End Date
10/15/2023
Operation
Continue Drilling 9-7/8'' Surface section F/ 1130' T/ 1502' PU 36K SO 31K ROT 34K GPM 405/ 450 SPP 959/ 1300 psi RPM 45/ 50 TQ 3.1/ 5.5K WOB 3/ 10K MW in/ out
8.9 ppg ECD 9.8/ 10.1ppg. CBU with 2100 sks. GPM 439 SPP 1191 psi.
Monitor well static. Attempted to POOH on elevators with 25K overpull. Pump Out of Hole F/ 1502' T/ 700' PU 36K SO 32K GPM 363 SPP 790 psi. with no problems.
POOH on elevators F/ 700' T/ 325' and lower Jar stand back in hole T/ 393'.
Grease & Inspect Crown, Blocks, Top Drive, Draworks, Iron Roughneck, Brake Linkage & Driveshaft. Clean out mud pump suction screens. Re-Adjust 37 pin control
cable on Top Drive so it doesn't rub against the kelly hose.
RIH on elevators F/ 393' T/ 1442' on elevators with no problems. Wash last stand down F/ 1442' T/ 1502' with no problems or fill. Calculated displacement 20.74 BBLs
Actual displacement 18.92 BBLs. Pump Hi-Vis sweep GPM 459 SPP 1300 psi. Sweep came back on time with 40% increase in cuttings.
Continue Drilling 9-7/8'' Surface section F/ 1502' T/ 2000' PU 42K SO 33K ROT 37K GPM 440 SPP 1335 psi RPM 50 TQ 5.2K WOB 1/10K MW in/ out 9.0 ppg ECD 9.5/
9.8ppg.
Continue Drilling 9-7/8'' Surface section F/ 2000' T/ 2681' PU 42K SO 36K ROT 42K GPM 440 SPP 1524 psi RPM 50 TQ 6.5K WOB 1/10K MW in/ out 9.0 ppg ECD
9.59ppg. Pump Hi Vis Sweep @ 2000' back on time 50% increase in cuttings.
Continue Drilling 9-7/8'' Surface section F/ 2681' T/ 2847' PU 52K SO 32K ROT 42K GPM 440 SPP 1380 psi RPM 50 TQ 6.5K WOB 1/10K MW in/ out 9.0 ppg ECD
9.3ppg. Distance to Plan 8.74' 1.19' Low 8.66' Right.
Report Number
5
Report Start Date
10/15/2023
Report End Date
10/16/2023
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147Permit to Drill (PTD) #:223-077
Page 2/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
Continue Drilling 9-7/8'' Surface section F/ 2847' T/ 2860'MD 2645'TVD PU 52K SO 36K ROT 42K GPM 420 SPP 1380 psi RPM 50 TQ 6.5K WOB 18K MW in/ out 9.0
ppg ECD 9.3ppg. Get BU sample & contact Geologist. Pump Hi-Vis sweep GPM 456 SPP
1367 psi. sweep came back on time W/ 25% increase in cuttings. Shoot final survey on bottom. 2821.71' MD 2611' TVD Inc 28.31 Az 138.97 Bit projection 7.22' F/ wp02
0.95' Above 7.15' Right.
Monitor Well Slight Seepage. POOH F/ 2860' T/ 1440' RIH F/ 1440' T/ 1503' PU 38K SO 32K POOH on elevators with no issues. Calculated hole fill 10 BBLs Actual hole
fill 9.5 BBLs.
Grease & Inspect Crown, Blocks, Top Drive, Draworks, Gear Box, Brake Linkage & Driveshaft. Clean out suction screens on mud pumps. Monitor well on trip tank losses
at 0.75 BPH.
RIH on elevators with no issues F/ 1503' T/ 2803' PU 56K SO 38K. Calculated displacement 24 BBLs Actual displacement 20.21 BBLs. At 2780' set down 20K M/U Top
Drive & filled pipe GPM 416 SPP 1386 psi. washed right through with no other obstructions to bottom of 2860'.
CBU @ 2860 Reciprocating pipe & Rotating PU 54K SO 36K ROT 44K GPM 427 SPP 1323 psi. RPM 60 TQ 6.7K MW in/ out 9.00ppg ECD 9.3. Pump Hi-Vis sweep after
BU sweep came back on time with 10% increase in cuttings.
Flow Check Well, Slight seepage. POOH on elevators with no issues F/ 2860' T/ 702' PU 54K SO 38K Calculated hole fill 21.6 BBLs Actual hole fill 25.2 BBLs.
POOH & stand back 5 stands of 4-1/2" HWDP. L/D 1 jt. HWDP & Jars. Stand back 3 stands of HWDP. L/D 6-3/4" Flex Collars. Download MWD data. L/D TM HOC,
EWR-M5 Collar, DM Collar, Break off 9-7/8" Kymera Bit & L/D 6-3/4" TerraForce Motor.
Clean & Clear rig floor.
R/U Parker TRS for running 7-5/8" Surface Casing. Power Tongs, Slips, Elevators, Dog Collar, Centralizers & Fill up line. Dummy run 7-5/8" Landing joint with hanger to
landing ring.
PJSM Run 7 5/8'' surface casing, make up float equipment and test floats (good) Continue RIH t/ 2852' M/U hanger and land on hanger. top filled every jt and filled every
ten jts, installed centralizers every other jt
R/U and circulate well staging pumps t/ 6 bpm 102 psi, reciprocating pipe.
PJSM, install cement head and lines, PT lines t/ 500 psi low 4100 psi high, batch up and pump 60 bbls 10.5 ppg spacer, drop bottom plug, pump 170 bbls of 12 ppg lead
cement @ 5 bpm 240 psi, followed by 33 bbls 15.8 ppg tail cement, drop top plug and displace cement w/ 125 bbls of 9 ppg spud mud
Report Number
6
Report Start Date
10/16/2023
Report End Date
10/17/2023
Operation
Cementers wash up to cuttings box & rig down. Clean pits. Open conductor valves, remove cement head, Back out landing joint, Remove casing elevators & Bale
extensions. Swizzle stick stack with black water. Flushed & blew down cement lines & Top Drive.
@ 5 bpm, bump plugs 125 bbls into displacement pressure up t/ 1350 psi 500 psi over final circulating pressure, bleed off .75 bbls bled back, floats held CIP 05:28am
10/16/23 R/D cementers no losses through out job 71 bbls cement back to surface.
Tear apart & remove vent line. Remove knife valve, 21-1/4" Annular Preventer, Tee & starting head. Bring in Cactus CTF-CTL-R-DBLO Housing, Clean off CFL Hanger &
set housing. Test between seals T/ 5000psi for 15 minutes. Engage Lockring with 16 Lock
Install test plug & 4-1/2" test jt. Purge stack & choke manifold with water. R/U test equipment & perform shell test t/ 3500 psi.
screws made up to 650 ft/lbs. Install Flow box, 11" 5K spacer spool & 11" 5K BOPE stack. Assemble Choke Line, Kill Line, Take R KBs, install bell Nipple, Connect all
hydraulic lines, pressure up accumulator & function test all components.
Test BOPs w/ 3.5'' and 4.5'' Test jts, Test t/ 250/3500 psi for 5 min low and 10 min high, Test upper lower and blind rams, Ann ular, CMV 1-13, HCR and Man choke and
kill, Auto and man IBOP, TIW and Dart, Outside 4'' kill line valve, Quadco tested gas alarms, Test PVT alarms.
State Inspector Adam Earl and BLM Inspector Quinn Sawyer witnessed test, No failures.
R/D test equipment, pull test plug and set wear ring.
Rack and tally DP, R/U and RIH P/U DP singles t/ 2305' 33k PUW POOH racking back DP f/ 2305' t/ surface.
R/U test equipment flood lines and test casing t/ 3500 psi f/ 30 min on chart pumped in 1.72 bbls holding test currently.
Report Number
7
Report Start Date
10/17/2023
Report End Date
10/18/2023
Operation
Continue Holding 7-5/8" Casing test T/ 3500psi. for 30 charted minutes. Bled off 1.7 BBLs. Blow down & R/D test equipment.
PU and MU 6 3/4" directional BHA as follows: 6 3/4" MMD54DM PDC jetted with 5 x 11's, motor, DM, PCG, ADR, ALD, CTN, PWD and TM collars, RFO of 256.93, MU
topdrive and shallow pulse tested, held PJSM and loaded sources, PU jars and single HWDP, cont RIH HWDP to 678'.
PU and singled in hole 64 jnts 4 1/2" DP, from 678' to 2661', MU topdrive and filled pipe.
Washed and reamed down from 2661' to 2768' and tagged up on wiper plug right on depth, 191 gpm-2011 psi, 30 rpm-4703 ft/lbs torque.
Drilled up wiper plugs and shoe track to 2851', rat hole cement to 2860', then 20' new formation to 2880', 203 gpm-1888 psi, 30 rpm-5700 ft/lbs torque, 1 to 4K wob.
Cuttings at bottoms up were sand with clay and some coal debris.
Pumped hi-vis spacer followed with 6% KCL mud at 9.1 ppg and displaced well to new mud. 208 gpm-1326 psi, 30 rpm-4200 ft/lbs torque.
Racked back one stand, RU test equipment on drill string and kill line, purged air, closed upper rams, pumped 15 gallons water to achieve 690 psi. Held 15 minutes,
pressure bled down to 575 psi, bled back 12.5 gallons, sent data to town, RD test equipment and obtained SPR's.
Cont Drilling 6 3/4" hole from 2880' to 3215' PUW 56k SOW 42k ROT 48k, 40 rpm 5.3k tq on bottom, 220 gpm 1517 psi SPP, 7k WOB, 140 diff, Max gas 13 units, ECD
9.85 ppg 9.0 ppg MW.
Cont Drilling 6 3/4" hole from 3215' to 3550' PUW 56k SOW 42k ROT 48k, 40 rpm 5.3k tq on bottom, 220 gpm 1517 psi SPP, 7k WOB, 140 diff, Max gas 13 units, ECD
9.85 ppg 9.0 ppg MW Distance to Plan 15.3' 11.64' Low 9.94' Left.
Report Number
8
Report Start Date
10/18/2023
Report End Date
10/19/2023
Operation
Cont drilling 6 3/4" hole from 3550' to 3891'. Rot wob 6-7K, 229 gpm-1740 psi, 70 rpm-5750 ft/lbs on bott torque, 124 ft/hr ROP . Sliding wob 7-8K, 218 gpm-1668 psi, 213
psi diff, 160 ft/hr ROP. MW 9.1+/vis 48, ECD's 9.9 ppg, BGG 41 units, max gas 251 units.
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 3/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
Pumped a 25 bbl hi-vis nutplug condet sweep around at 217 gpm-2031 psi, 80 rpm-6680 ft/lbs off bott torque. Sweep back on time with a 20% increase in cuttings.
Obtained on bott survey, SPR's and flow check was static.
At 3700' adding 2.5 ppb each of BaroTrol plus and Soltex, 5 ppb Steelseal 25 (black products)
Pulled up hole on elevators from 3890' to 2961', up wt 68K. At 2961' we were swabbing. MU topdrive and backreamed at 200 gpm-20 rpm to 2859', S/O and parked at
2901'.
Serviced rig and topdrive, changed grabber dies on topdrive.
TIH on elevators from 2901' to 3027' and set down 20K 3 times (top of slide). MU topdrive, washed and reamed down to 3088'. COnt TIH on elevators to 3107' and set
down again (bottom of slide). MU topdrive, washed and reamed down to 3150'. TIH on elevators to 3828' with no issues. MU topdrive, filled
Resumed drilling from 3891' to 4015'. Sliding wob 8K, 209 gpm-1589 psi, 109 psi diff, 43 ft/hr ROP. Rot wob 2-6K, 219 gpm-1676 psi, 70 rpm-6200 ft/lbs on bott torque,
80 ft/hr ROP. MW 9.2/vis 52, ECD's 9.9 ppg, BGG 85 units, max gas 326 units.
pipe, washed to bottom.
Cont drilling from 4015' to 4264' PUW 80k SOW 54k ROT 65k, 70 rpm 7k tq on bottom, 218 gpm 1739 psi SPP, 7-9k WOB 279 diff, Max Gas 616 units, MW 9.1 ppg ECD
9.87 ppg
Cont drilling from 4264' to 4415' PUW 80k SOW 54k ROT 65k, 70 rpm 7.7k tq on bottom, 210 gpm 1816 psi SPP, 7-9k WOB 279 diff, Max Gas 331 units, MW 9.2 ppg
ECD 10 ppg Distance to Plan 6.69' 5.61' Above 3.65' Left All data current till 0430 hrs Wellez swap
Report Number
9
Report Start Date
10/19/2023
Report End Date
10/20/2023
Operation
Cont drilling 6 3/4" hole from 4456' to 4634'. Rot wob 8-9K, 215 gpm-1698 psi, 65 rpm-6500 ft/lbs on bott torque, 15 to 80 ft/h r ROP. MW 9.1+/vis 48, ECD's 10.0 ppg,
BGG 13 units, max gas 635 units. At 4530' added 3 sacks nut plug to suction pit in hopes to clean up BHA, get better ROP.
Cont drilling 6 3/4" hole from 4634' to 4881'. Sliding wob 10K, 211 gpm-1782 psi, 176 psi diff, 35 ft/hr ROP. Rot wob 9K, 224 g pm-1826 psi, 70 rpm-7067 ft/lbs on bott
torque, 20 to 80 ft/hr ROP. MW 9.1+/vis 50, ECD's 10.0 to 10.3 ppg, BGG 88 units, max gas 470 units.
Pumped a 25 bbls lo-vis nutplug sweep around at 216 gpm-1570 psi, 70 rpm-7937 ft/lbs off bott torque. Sweep back on time with 10% increase in cuttings. Obtained on
bottom survey, SPR's and flow check showed slight seepage.
Pulled up hole from 4881' to 3846' on elevators, S/O and parked at 3890'.
Service Rig and top drive, Grease crown, reset pason system
RIH f/ 3891' t/ 4881' wash last stand to bottom, No issues, Pump Low vis sweep
Cont drilling 6 3/4" hole from 4881' to 4945'. Sliding wob 10K, 211 gpm-1707 psi, 104 psi diff, Rot wob 9K, 70 rpm-7200 ft/lbs on bott torque. PUW90k SOW 68k ROT 68k,
MW 9.1+/vis 50, ECD's 10.17 ppg max gas 234 units.
Cont drilling 6 3/4" hole from 4945' to 5156'. Sliding wob 10K, 215 gpm-1780 psi, 200 psi diff, Rot wob 9K, 70 rpm-8200 ft/lbs on bott torque. PUW 86k SOW 60k ROT
69k, MW 9.1+/vis 50, ECD's 10.1 ppg max gas 203 units.
Report Number
10
Report Start Date
10/20/2023
Report End Date
10/21/2023
Operation
Cont drilling 6 3/4" hole from 5156' to 5339'. ROT wob 9 to 10K, 221 gpm-1770 psi, 80 rpm-7860 ft/lbs on bott torque, 16 to 70 ft/hr ROP. MW 9.2/vis 51, ECD's 10.1 to
10.3 ppg, BGG 14 units, max gas 61 units.
Cont drilling 6 3/4" hole from 5339' to 5447'. ROT wob 10K, 218 gpm-1817 psi, 60 to 80 rpm-7250 to 7860 ft/lbs on bott torque, 12 to 50 ft/hr ROP. MW 9.2+/vis 51, ECD's
10.3 ppg, BGG 32 units, max gas 167 units. Added 3 sacks nutplug to suction at 5392'. Pumped nutplug sweep at 5442'.
Cont drilling 6 3/4" hole from 5447' to 5658' PUW 96k SOW 60k ROT 76k 66 RPM 9.2k tq, 220 gpm 2283' psi SPP, 7-17k WOB, 325 diff, Max gas 163 units, MW 9.15
ppg ECD 10.47 ppg
Continue Drilling 6 3/4'' Hole section f/ 5658' t/ 5749' 98k PUW 63k SOW 75k ROT, 65 RPM 7.5k tq on bottom, 215 gpm 1850 psi 170 diff, 7-17k WOB Max Gas 186
units, 9.25 ppg MW 10.34 ppg ECD , Distance to Plan 6.16' .89' Low 6.10' Right
Report Number
11
Report Start Date
10/21/2023
Report End Date
10/22/2023
Operation
Cont drilling 6 3/4" hole from 5749' to 5858'. Rot wob 20K, 213 gpm-1938 psi, 65 rpm-7300 ft/lbs on bott torque, 12 to 80 ft/hr ROP. MW 9.3/vis 47, ECD's 10.3 ppg, BGG
22 unnits, max gas 56 units. Centrifuge is down for the count, no longer operable.
Cont drilling from 5858' to 5897'. Rot wob 20K, 211 gpm-2500 psi, 70 rpm-7548 ft/lbs on bott torque, 8-30 ft/hr ROP. MW 9.3/vis 48, ECD's 10.3 ppg, BGG 11 units, max
gas 107 units.
At 5860’ while rotating ahead, there was a sudden spike in diff pressure exceeding 700 psi and pump pressure increased from 1970 to 2333 psi. PU off bottom,
backreamed stand, diff pressure dropped back to normal, pump pressure slowly decreasing. Slid from 5860’ to 5864’ with no motor issues so resumed rotating ahead. Put
3 sacks nutplug in suction pit and as soon as nutplug got to BHA, pump pressure increased from 2350 to 3253 psi, then slowly decreased. ROP dropped off to the point
decision was made to POOH for bit change.
CBU at 211 gpm-2390 psi, 80 rpm-9831 ft/lbs off bott torque, obtained SPR's, flow check showed slight seepage.
Pulled up hole on elevators, up wt 110K, from 5897' to 5561', started swabbing, MU topdrive, cont to backream up hole from 5561' to 2850', 208 gpm-2751 psi, 50
rpm-6500 to 8300 ft/lbs off bott torque.
POOH on elevators f/ 2850' t/ HWDP, Rack back in derrick along with jars stand, no issues
PJSM unload sources, clear floor, P/U and Download MWD
Report Number
12
Report Start Date
10/22/2023
Report End Date
10/23/2023
Operation
L/D TM, PWD, CTN, ALD and DM collars, closed blinds, drained motor, broke off bit and L/D motor. Bit graded : 2-2-CT-A-X-2-PN-PR. Bit had two plugged jets and two
packed off junk slots
Serviced rig and topdrive, functioned HCR's, re-set flow riser (snagged by bit), adjusted brake linkage, when C/O grabber dies found block assembly was damaged, made
arrangements to get replacement sent to Beluga, staged new bit, motor and TM collar.
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 4/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
MU new HDBS GT54D PDC bit jetted w/5 x 11's, motor w/1.5° bend, DM and PCG collars, scribed with an RFO of 99.21°, MU ADR, ALD, CTN, PWD and new TM collar,
uploaded MWD data, shallow pulse tested, held PJSM and loaded sources, RIH 1 stand HWDP.
Replaced Topdrive grabber die block assembly.
Cont TIH with remainder HWDP and jars to 678'.
Cont TIH with DP from 678' to 2840', filled pipe, tripped in open hole to 4349', washed/reamed down to 4381', on elevators to 5419', washed/reamed to 5434' and gas
started climbing.
Cont to circ and work pipe at 202 gpm-1151 psi, 40 rpm-8900 ft/lbs off bott torque, gas climbed to 5000 units for 5 min, dropped to 1894 units, then back up to 5000 units
for 10 minutes. Once gas down to 1365 units and falling, shut down to RIH.
TIH on elevators to 5770', wash/ream to 5871', pumped 20 bbl lo-vis nutplug sweep and washed/reamed to bottom at 5897'.
Resumed drilling 6 3/4" hole from 5897' to 6090' PUW 102k SOW 64k ROT 79k 60 RPM 9.2k tq on bottom, 202 gpm 1487 psi SPP, 5k WOB Max Gas 5000 units MW
9.35 ECD 10.14
Continue drilling 6 3/4" hole from 6090' to 6349' PUW 107k SOW 62k ROT 79k 60 RPM 10.4k tq on bottom, 206 gpm 1630psi SPP, 7k WOB Max Gas 100 units MW 9.4
ECD 10.32
Distance to plan 8.77' 3.91' Above 7.82' Right
Report Number
13
Report Start Date
10/23/2023
Report End Date
10/24/2023
Operation
Cont drilling 6 3/4" hole from 6349' to 6636', rot wob 3-5K, 211 gpm-1675 psi, 75 rpm-10,500 ft/lbs on bott torque, 22 to 100 ft/hr ROP. MW 9.4/vis 48, ECD's 10.4 to 10.5
ppg, BGG 31 units, max gas 433 units.
Cont drilling 6 3/4" hole from 6636' to 6939', rot wob 5-6K, 213 gpm-1766 psi, 75 rpm-10,970 to 11,223 ft/lbs on bott torque, 8 to 80 ft/hr ROP. MW 9.4+/vis 48, ECD's
10.6 to 10.7 ppg, BGG 42 units, max gas 1365 units.
Load mud product and equipment on trailers that is no longer needed on west side, for barging to east side.
Cont drilling 6 3/4" hole from 6939' to 7244' TD PUW 116k SOW 72k ROT 90k 75 rpm 11.3k tq on bottom, 205 gpm 1659 psi SPP 253 psi Diff, 6k WOB, Max GAs 220
units MW 9.5 ppg ECD 10.66 ppg
Distance to Plan 5.93' 3.7' Low 4.63' Left
Circulate Hi Vis Sweep around sweep back 250 stks early and 20% increase in cuttings
Make wiper trip f/ 7244' t/ 5897' with no issues, worked through a fdew tight spots 15-20k over pulls, wiped clean, RIH f/ 5897' t/ 7244' washed last stand to bottom no
issues.
CIrculate Hi vis Sweep around, 3981 units of gas halfway through bottoms up, Sweep back on time 30% increase in cuttings returned, Shut down flow check well static,
Blow down top drive
POOH f/ 7244' t/ 6888' on elevators
Report Number
14
Report Start Date
10/24/2023
Report End Date
10/25/2023
Operation
Cont POOH on elevators from 6888' to 5187', up wt 120K. At 5187' we started to swab in a couple tight spots. MU topdrive and co nt to pump OOH from 5187' to 3947' at
201 gpm-1128 psi, up wt 80K. Pulled at 30 to 40 ft/min with no issues. At 3947' pulling in tight hole, seeing pressure increase and flow trying to drop off. Started
backreaming at 40 rpm-4900 ft/lbs torque, to 3642'.
Cont to backream OOH from 3642' to surface shoe at 2851'. Last three stands to shoe were very tight, had to inch our way up hol e, 192 gpm-1101 psi, 40 rpm-4900 ft/lbs
torque, up wt 52K, very little gas entire trip. Pulled into shoe, then slacked off and parked at 2875' (below rathole cement).
CBU staging up to 221 gpm-1122 psi, 40 rpm-3785 ft/lbs torque, BGG 2 units. Shut down and did 15 min flow check, fluid dropped 1' in wellbore. Broke off topdrive and
blew down, dropped 2.39" OD hollow drift down DP.
Cont POOH from 2875' on elevators inside surface casing at 30 to 40 ft/min to BHA at 678'.
Cont POOH L/D HWDP from 678' to TM collar at 120', held PJSM, removed sources, plugged in and downloaded MWD data, L/D remainde r smart tools, motor and bit.
Bit graded a 1-1 in gauge.
Cleaned and cleared rig floor/catwalk. Serviced rig- Greased & inspected crown, blocks, TD, wash pipe, IR, DWKS, brake linkage, and drive shaft.
R/U TRS. loaded 3.5" 9.2# L-80 Wedge 563 liner on catwalk racks.
Held PJSM on running liner. M/U shoe track and BakerLoc connections. Tested floats (ok). Cont. running 3.5" 9.2# L-80 Wedge 563 as per run tally @ 30 fpm F/surface
-T/2816'.
M/U XO. Broke circ. CBU, staging pump up to 6 bpm. P/U-32K S/O-28K GPM-252 SPP-346 psi MW-9.6 ppg.
Report Number
15
Report Start Date
10/25/2023
Report End Date
10/26/2023
Operation
Blew down topdrive, cont PU single in hole with 3 1/2" liner from 2816' to 4554', MU XO and topdrive. Torqued liner pipe to opt imum of 2900 ft/lbs.
CBU staging pump up to 6 bpm-510 psi, max gas 50 units, no losses. Rig mechanic removed hole fill pump for bearing change on shaft.
Broke off topdrive and blew down same, PU Baker HRD-E ZXP/Flex Lock V liner hanger assembly, MU 5 1/2" x 3 1/2" XO on bottom and MU assembly on stump,
removed TRS tubing tongs from rig floor, mixed and poured xanplex, MU 1st stand 4 1/2" DP with XO and eased down to 4663', up wt 52K, dwn wt 37K.
Circulated 1 liner volume plus at 166 gpm-325 psi, 13% flow until crews changed out.
Cont TIH on 4 1/2" DP at 20 ft/min from 4663' to 5656' with no issue, top filling DP on the fly. Topped off drill string and MU topdrive. CCI cont loading trailers with
equipment to stage at barge landing.
Circulated 1200 strokes at 122 gpm-275 psi. Released sample catchers and DD's.
Cont TIH at 20 ft/min from 5656' to 6647', up wt 52K, dwn wt 44K, top filled on the fly, topped off drill string and MU topdriv e. Cementers on location with pump truck and
bulkers, staged trucks and RU to cement line in cellar.
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 5/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
Circulated 1200 strokes at 120 gpm-353 psi.
Blew down topdrive, cont TIH at 20 ft/min from 6647' to 7244' filling drill string on the fly, tagged bottom 7' deep. LD top si ngle of stand 43, up wt 75K, dwn wt 50K. Topped
off drill string and MU topdrive.
Circulated staging up to 169 gpm-538 psi, then up to 212 gpm-618 psi, then up to 221 gpm-678 psi. Had a max of 3373 units gas prior to bottoms up that dropped to 974
units, then back up to 2787 units over an hour. With gas down to 378 units shut down pump. Notified state & BLM of up coming MIT's.
Broke off topdrive and blew down, PU and MU Baker cement head, torqued through with topdrive to MU all XO's and pup joints. RU cement and wash up hoses to cement
head, lined up and circ through cement head at 221 gpm-711 psi while cementers finished RU.
Halliburton pumped 5 bbls water to flush and fill lines. Shut in at Baker cement head and PT lines at 1020 psi low 5300 psi high. Good tests.
Lined up Baker cement head to Halliburton, pumped 30 bbls 10.5 ppg Tuned Spacer at 4.5 bpm- 630 - 625 psi, followed with 191 bbls (448 sx) 12 ppg Type I II Lead
cement at 4.5 bpm, 625 - 200 psi, followed with 26 bbls (122 sx) 15.3 ppg Type I II Tail cement at 3 bpm, 200 – 156 psi. Had 2 pps bridgemaker LCM in lead cmt. Baker
released dart, Halliburton then displaced with 9.65 ppg 6% KCL mud at 4 bpm- 156 – 1155 psi ICP. With 15.5 bbls to go, reduced rate to 3 bpm- 1155 - 1330 psi. Lost all
returns 60 bbls into displacement. Bumped drill pipe dart @ landing collar at 75.5 bbls into displacement (calculated at 75.5 b bls). FCP 1330 psi. Halliburton increased to
and held 1862 psi (532 over fcp) for 1 minute, then increased pressure to 2500 psi for 3 minute to set hanger. Slacked off on blocks from 58K to 15K, giving us a good
indication hanger was set. CIP at 21:49 on 10-25-23. Pressured up to 3360 psi to set packer with good indication of packer setting. Cont. pressuring up to 4560 psi
seeing pusher tool release. Bled off pressure back to truck. Bled back 1 bbls to truck and floats held. P/U to 42K with good indication of release. R/D cmt hoses and L/D
Baker cmt head. M/U TD to stump to circulate. Pressured up to 1080 psi on drill string and PU 21’, pressure dumped. CBU at GPM-340 SPP-322 psi. Had 30 bbls spacer
and 9 bbls cement/contaminated mud at the shakers. Circulated an addition BU x2 and added 2 sxs of walnut to suction pit to scrub pipe. Lost 54.5 bbls during the cmt
job.
Flow checked well (static). POOH F/2598'-T/2475'. P/U-42K S/O-35K
PU RIH with HWDP
Crew change, held PTSM. Cont. POOH F/2475'-T/Baker running tool. Inspected tool (ok). B/D and L/D baker running tool. Calculated hole fill- 19.32 bbls Act- 20.04 bbls
Diff- .72 bbls
Cleaned & cleared rig floor. P/U & B/D Baker cmt head. M/U Johnny Wacker on single, drained and flushed stack w/ black water.
P/U & M/U Baker PBR mill assembly. RIH F/surface- T/1691'. Replaced HYD hose on IR w/ same. Resumed RIH F/1691' to current depth of 2615'.
Report Number
16
Report Start Date
10/26/2023
Report End Date
10/27/2023
Operation
Dress liner top at 2651' as per Baker Rep, 3 bpm-20 rpm-2950 ft/lbs torque, 3K max weight on upper dress mill.
Cont to circ, held PJSM, pumped 20 bbl hi-vis spacer followed with 146 bbls corrosion inhibited water at 496 gpm-461 psi. Had mill 1' off no-go as IFW rounded the corner
to flush SBR. Picked up out of SBR and finished displacement. LD top single and blew down topdrive.
Monitored well bore for flow, wait on vac truck to return from G&I to vac wiper balls.
POOH LD 86 jnts DP and BAker polish mill. CCI vac'ing wiper balls thorugh DP, clean and dry threads, re-doped threads and installed protectors for transport.
MU diffuser sub and RIH with DP from derrick to 2230', MU topdrive and circulated 5 minutes at 596 gpm-549 psi to flush pipe.
POOH LD DP, cont pit cleaning, load and stage pipe bunks for barge to east side, lay over and stage upright water tank for transport to east side.
RIH with last batch DP from derrick to 1798', MU topdrive and flushed pipe at 597 gpm-167 psi. Blew down topdrive.
POOH L/D remainder of 4.5" DP F/1798'-T/surface w/ calculated hole fill. Vacuuming wiper balls through tubulars, cleaning & redoping threads, and installing thread
protectors on tight.
P/U and singled in the hole w/ HWDP F/surface -T/653'. Pumped through HWDP w/ CIW, and L/D same. Finished hauling off mud & cleaning tank bottom. Worked of
flushing pit system w/ Barklean and CIW.
M/U wear ring retrevial tool. drained stack. Pulled wear ring, L/D same. M/U well head brush tool. Flushed & brushed well head w/ CIW. Blew down TD.
R/U testing equip. Flooded stack & lines, purged out air. Tested casing/liner lap T/3500 psi on chart for 30 min (Good test). Pumped in 2.08 bbls Bled back 2.08 bbls R/D
testing equip.
R/U TRS casing equip. Stagged Baker bullet seal, XO, and pup on catwalk. Filled racks w/ 3.5" tubulars. Held PJSM on running tie back assembly.
P/U & M/U Baker tie back seals as per Baker rep. Cont. running 3.5" 9.2# L-80 Wedge 563 tie back as per run tally F/surface - T/1154'.
R/U Pollard spooling unit and control line sheave in the derrick. P/U chem sub. M/U control line to chem sub and tested tie in connection T/1000 psi for 5 min (ok). Cont.
hold 200 psi on control line while cont. to run 3.5" tie back string.
Cont. running 3.5" tie back completion F/1163' to current depth of 2207'.
Report Number
17
Report Start Date
10/27/2023
Report End Date
10/28/2023
Operation
Cont PU single in hole with 3 1/2" tubing, torqued to optimum of 2900 ft/lbs, from 2207' to 2614'. Up wt 28K, dwn wt 26K. PU two extra joints and at 2650' saw seals enter
SBR. Tagged no-go with WLEG at 2659'. L/D two joints, MU space out pups on bottom of last joint (two totaling 17.61'), swapped to 4 1/2" elevators, MU landing joint and
hanger, terminated control line, removed tubing tongs from rig floor, Pollard Rep tested control line connection at hanger, dra ined BOP stack, pulled bushings, S/O down
wt 24K, landed hanger at 20.15' RKB. Wellhead Rep tested hanger seals at 5000 psi for 10 min, good test.
Rotated landing joint 6 turns to left to solid stop engaging lock ring in wellhead, rotated right 4 turns, pull tested to 40K, hanger locked into wellhead.
Installed headpin on landing joint, topped off with water, RU test pump, chart recorder and hoses, purged air, cleaned up rig floor and cellar, installed gauge on IA,
AOGCC Rep on location at 09:45.
Pumped 1 bbl down tubing and pressured up to 3775 psi, held 30 min on chart, good test, bled back 1 bbl. Installed test hose on IA, gauge on tubing, pumped 1 bbl and
pressured up to 2780 psi, held 30 min on chart, good test, bled back 1 bbl. RD test equipment, blew down test pump and hoses.
Removed landing joint and L/D, Wellhead Rep installed 2 way check in hanger.
Flushed all surface equipment, pumps, topdrive, cement manifold, BOP stack, choke manifold, poorboy degasser with BaraKlean solution, fresh water, then corrosion
inhibited solution. Blew all surface lines and equipment down.
Undress rig floor, load baskets and trailers with various equipment, inventoried same, to be staged for barging to east side.
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 6/6
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
R/D flow line, flow box, and removed chains & binders from stack. R/D choke & kill lines. De energized Koomey. Removed upper & lower VBR's and blind rams from
stack. Pulled ring cap off annular & cleaned/regreased element, reinstalled same. Pressure washed ram cavities, coated w/ corrosion X, and prepped for cold stack.
Removed all accumulator lines & fittings from stack. R/D & prepped MP#2 for cold stack. Winterized test pump. Removed hatch on degasser, pressure washed inside
vessel, and applied corrosion X on floats & levers. Greased choke manifold valves and installed caps of ports. Cleaned Y strain ers on accumulator and prepped for move.
R/D mud lab, loaded out, and hauled to barg landing.
Crew change, held PTSM. Cont. w/ cleaning, pickling rig, R/D, and prepping for move & cold stack. N/D and removed stack out of the way w/ bridge cranes. Removed
spacer spool off bottom of stack. Called out WHR, installed lower section of tree on the well head. Tested neck seals, voild, a nd lower section on tree to 5000 psi for 10
min (ok). Removed TWC. Filled choke manifold w/ HYD fluid. Changed out gear oil in agitator gear boxes. R/D centriguge to be se nt to town for maintence. Vacuumed out
water from hot well tank in little boiler. Removed bails, wash pipe, and Kelley hose from TD. TD is prepped to check end play.
API: 50-283-20193-00-00 Field: Beluga River
Sundry #:
State: ALASKA
Rig/Service: HEC 147
Page 1/2
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Jobs
Actual Start Date:11/3/2023 End Date:11/21/2023
Report Number
1
Report Start Date
11/3/2023
Report End Date
11/4/2023
Operation
PJSM, Discuss daily operations with crews & 3rd party
Crew travel to location
Spot in & rig up equipment, swap reels & set up injector head.
Pressure test BOPE 250 low/ 3000 high 0-fails 0-retests, Make up coil connector, Pull test to 30k, Load string & pressure test to 3000 psi-good,
Run in hole with clean out bha 2.75" on motor to tag @ 7175'
Swap well over to FW. 45 bbls away, begin Pooh pumping pipe displacement. 90 bbls away. Off pump. Tagged up on surface, swab check. SIBD.
Unstab from well. Break down BHA. Install 2.13” N2 nozzle on connector. Lay down riser, rack back injector head.
Spot Ak Eline equipment. Begin rigging up Eline with 9/32” cable. Coil crew rigging up 2” 1502 hardline from reel to choke for N2 reverse out. Transfer N2 between
transports/pump.
M/U grease head and BHA = 1-11/16” x 1’ Cable head w/ 1-3/8” FN, 1-11/16” x 3’ bow spring, 1-11/16 x 10’ CBL, 1-11/16” x 3’ bow spring, 7’ titan 1-11/16 gun gamma,
2.5’ 6 blade bow spring w/bull nose. Pick up lubricator and stab on well.
RIH w/AK Eline CBL BHA - Logged CBL from 7,175' elm to surface. Good data, log shows good cement bond. Send Uncorrelated log to OE.
RDMO AK Eline.
Pick up injector head and risers. Stab on wellhead.
RIH w/2.13" N2 nozzle.
Report Number
2
Report Start Date
11/11/2023
Report End Date
11/12/2023
Operation
Report Number
3
Report Start Date
11/17/2023
Report End Date
11/18/2023
Operation
Mob equipment to location, Spot in & rig up, Prepare to perf in AM.
Report Number
4
Report Start Date
11/18/2023
Report End Date
11/19/2023
Operation
PJSM, Discuss daily operations, Crew travel to location, Cont. rigging up, Repair lubricator, Pick up lube & guns for run #1, T est 250 low/2500 high-good, Run in hole with
gun #1, Perform correlation pass & confirm depth-good, TS-CCL 9', perf f/ 6712'-6726', (5-1600, 10-1600,15-1600), Pull out of h ole, Pick up Gun #2 & run in hole to
correlate, TS to CCL=9', Perf 6031'-6041'(OG-1503, 5-1497, 10-1493,15-1493), Pull out of the hole, PIck up gun #3 & run in hole to perf, TS to CCL=9', f/5619' -5629'
(OG-1525, 5-1542, 1570,15-1598), Pull out of the hole, Check plug (dry), Pick up gun #4 & run in hole to perf, TS to CCL=9, run in & correlate to perf TS-CCL=9'
5516'-5522', (OG-1683, 5-1672, 10-1660, 15-1653), Pull out of hole with gun #4, Shut in & secure well, lay down equipment.
Report Number
5
Report Start Date
11/19/2023
Report End Date
11/20/2023
Operation
PJSM, Discuss daily operations, Crew travel to location, Check wellhead pressure SITP: 1690 psi, Pick up & rig up with GPT/GR/CCL, Test lubricator-good, Run in hole
with GPT, Log up fluid level @ 6800', Temp drop @ 6031', Pull up hole to 5006', Flow well down to 848 psi, Run in hole with GP T, Fluid level @ 6630', Flow well @ 550
psi @ 800 mcf, Pull out of the hole with GPT, Pick up guns 5 & 6 on switches, Perform correlation pass from 5300' to 5000' adju st, Perf with gun #5 CCL to TS=16.7', Perf
f/ 5160'-5169', Flowing (OG-651, 5-651, 10-651, 15-651), Pull up to perf gun #6 CCl to TS=8.2', Perf f/5129' - 5134, (OG-651, 5-667, 10-688, 15-753), Pull out of the hole,
Shut in & secure well, Lay down tools.
Report Number
6
Report Start Date
11/20/2023
Report End Date
11/21/2023
Operation
PJSM, Discuss daily operations, Crew travel to location, Pick up lubricator & gun # 7, Run in hole & perform correlation pass, Adjust 1' up, CCL-TS=9', Perf f/5101-5116
(OG-800 @ 858 mcf, 10-790, 15-77s psi @ 671 mcf) Pull out of hole, Pick up gun #8, Run in hole & correlate, To perf f/5060'-507 4', (OG-809 psi @ 559 mcf, 5-766,
10-748, 15-744 psi @ 489 mcf), Pull out of hole, Pick up guns 10 Issue with gun 9, Run in hole & correlate, CCL-TS=12.5', Perf/ 5041'-5044', (OG-741 @ 496 mcf, 5- 713,
10-700, 15-693 @ 713 mcf), Pull out of hole, PIck up gun #9 run in hole to correlarte & perf, CCL-TS=14.2', Perf f/5050'-5054', (OG 743 @ 1256 mcf, 5-698, 10-694,
15-693 @ 1095 mcf), Pull out of hole, Pick up guns 11-14, Run in hole & perform correlation pass-on depth, Pull in to perf CCL-TS=27.5', 5037'-5040' 9 (OG-483 @ 2118
mcf, 5-483) Pull up to #12 CCL-TS=22.7', 5030'-5033', (OG-483 @ 2122 mcf, 5-484) Pull up to gun #13, CCL-TS=15.2', 5021'-5026', (OG-485 psi @ 2123 mcf, 5-486),
Pull in to perf CCL-TS=9.7', 4946'-4950' (OG-483 psi @ 2123 mcf, 5-483, 10-480, 15-483 @ 281 mcf), Pull out of hole, Gun 11 misfire, Pick up guns 15-16, Make up &
run in hole, Correlate-good, pull in to perf with gun #15 CCL-TS=19.7', 4928'-4933', (OG 491 @ 2119 mcf, 5-565), Pull up hole, CCL-TS=7.5', 4868'-4878', (OG-567 psi @
2569 mcf, 5-567,10-564, 15-564 @ 2563 mcf), Pull out of hole & secure well, Flow well overnight.
Report Number
7
Report Start Date
11/21/2023
Report End Date
11/22/2023
API: 50-283-20193-00-00 Field: Beluga River
Sundry #: 323-587
State: ALASKA
Rig/Service:Permit to Drill (PTD) #:223-077
Page 2/2
Well Name: BRU 221-35
Report Printed: 12/18/2023www.peloton.com
Well Operations Summary
Operation
PJSM, Discuss daily perf plan, Crew travel to location, Pick up & rig up Gun #11 (misfire from 11/20/23), Run in hole & corrrel ate-good, Pull up to perf CCL-TS=12.5',
5037'-5040' (OG-950), Pull out of hole & check gun (misfire), Lay down gun & pick up guns 17 to 19, Run in hole & get correlation pass, On depth, Pull up to shoot
CCL-TS=21.5', 4855'-4859', (OG-1000, 5-1000), Pull up hole to perf, CCL-TS=12', 4842'-4848', Pull up to hole shoot CCL-TS=7.5', (OG-1000, 5-1000), Pull out of hole,
Pick up guns 20-21, Run in hole & correlate, Pull up to perf CCL-TS=19', 4792'-4798', (OG-950, 5-950), Pull up to perf CCl-TS=9.2', 4735'-4743' (OG-950, 5-950), Pull out
of hole & pick up guns 22-24, Run in hole & correlate, perf CCl-TS=17.5', 4728'-4733 (OG-416 @ 2262 mcf), Pull up hole, CCl-TS=12', 4714'-4717', (OG-420 @ 2286
mcf, 5-420), Pull up hole, CCL-TS=8.2', 4666'-4668' (OG-416 @ 2262 mcf, 5-412,10-408, 15-403 @ 2185 mcf), Pull out of the hole & pick up guns 25-26, Run in hole &
correlate, CCL-TS=16, 4647'-4752' (OG -520 @ 1743 mcf, 5-527), Pull up hole, CCL-TS=7.5', 4632'-4638', (OG-526 @ 1767 mcf, 5-527, 10-528, 15-530 @ 1765 mcf)
Pull out of hole, Secure well, Rig down & mob to D-pad.
Report Number
8
Report Start Date
11/27/2023
Report End Date
11/28/2023
Operation
API: 50-283-20193-00-00 Field: Beluga River
Sundry #: 323-587
State: ALASKA
Rig/Service:
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C9 C
C
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.10.24 11:19:52 -08'00'Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.10.24 14:42:33 -08'00'
Page 1/1
Well Name: BRU 221-35
Report Printed: 12/18/2023
www.peloton.com
Casing
Surface
Wellbore
Wellbore Name:
221-35 Total Depth of Wellbore (ftKB):
7,244.00 Original KB/RT Elevation (ft):
97.80
RKB to GL (ft):
18.50 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft):
PBTDs
Depth (ftKB):
7,175.1
Casing
Casing Description:
Surface Run Date:
10/16/2023 Set Depth (ftKB):
2,850.72
Casing Weight on Slips (1000lbf):
0.0 Pick Up Weight (1000lbf):
0.0 Block Weight (1000lbf):
15,000.0
Make-Up Contractor:
TRS Number Hrs to Run (hr):
0.00 Ft/Min (ft/min):
Run Job:
231-00132 BRU 221-35 Drilling, Drilling -
Drilling, 10/11/2023 06:00
Set Depth (ftKB):
2,850.72 Set Depth (TVD) (ftKB):
2,637.3
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)
Hanger 15.01 6.87 BTC Cactus 0.43 20.86 20.44
1 Casing Pup Joint 7 5/8 6.87 29.70 L-80 TXP Tenarus 2.72 23.58 20.86
69 Casing Joints 7 5/8 6.87 29.70 L-80 TXP Tenarus 2,709.65 2,733.23 23.58
1 Casing Joints 7 5/8 6.87 29.70 L-80 BTC Tenarus 37.01 2,770.24 2,733.23
Float Collar 8.622 0.00 29.70 L-80 BTC Innovex 1.31 2,771.56 2,770.24
1 Casing Joints 7 5/8 6.87 29.70 L-80 BTC Tenarus 40.22 2,811.78 2,771.56
1 Casing Joints 7 5/8 6.87 29.70 L-80 BTC Tenarus 37.47 2,849.25 2,811.78
Float Shoe 8.622 0.00 29.70 L-80 BTC Forum 1.48 2,850.72 2,849.25
Page 1/1
Well Name: BRU 221-35
Report Printed: 12/18/2023
www.peloton.com
Cement
Surface Casing Cement
Type
Casing
Description
Surface Casing Cement
Cemented String
Surface, 2,850.72ftKB
Wellbore
221-35
Job
231-00132 BRU 221-35 Drilling, Drilling -
Drilling, 10/11/2023 06:00
Cementing Start Date
10/16/2023
Cementing End Date
10/16/2023
Top Depth (ftKB)
22.0
Cement Stages
Stage Number: 1
Description
Surface Casing Cement
Top Depth (ftKB)
22.0
Bottom Depth (ftKB)
2,850.7
Top Measurement Method
Returns to Surface
Pump Start Date
10/16/2023
Cement in Place At
10/16/2023
Final Circulating Pressure (psi)
850.0
Plug Bump Pressure (psi)
1,350.0
Full Return?
Yes
Returns During Job (%)
100
Volume to Surface (bbl)
71.0
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) Tuned 1.20 10.50 60.0 60.0 4 Halliburton
Lead Slurry I II 397 2.44 12.00 170.0 170.0 5 Halliburton
Tail Slurry I II 173 1.16 15.80 33.0 33.0 5 Halliburton
Displacement Spud Mud 9.00 125.0 125.0 5 Halliburton
Post Job Calculations
Subtype Value
Page 1/1
Well Name: BRU 221-35
Report Printed: 12/18/2023
www.peloton.com
Casing
Siner 1
Welluore
Welluore Name:
221-35 f otal beptT oDWelluore hDt( BK:7,244.00 ) riginal ( B/Rf OleEation hDtK:97.80
R( B to v S hDtK:18.50 ( B-Casing Glange bistance hDtK: ( B-f Luing Fanger bistance hDtK:
PBf bs
beptThDt( BK:7,175.1
Casing
Casing bescription:
Liner 1 RLn bate:
10/25/2023 Het beptT hDt( BK:7,244.00
Casing WeigTt on Hlips h1000luDK:PickUpWeigTth1000luDK:75,000.0 Block WeigTt h1000luDK:15,000.0
Make-Up Contractor:
TRS NLmuer Frs to RLn hTrK:17.48 Gt/Min hDt/minK:6.91
RLn Jou:
231-00132 BRU 221-35 Drilling, Drilling -
Drilling, 10/11/2023 06:00
Het beptT hDt( BK:7,244.00 Het beptT hfVbKhDt( BK:6,904.1
Centralizer betail:
1 every other joint, total 71
AttriuLte HLutype: ValLe:
Pipe Reciprocated?:
No Pipe Rotated?:
No Gloat Gailed?:
No
f est HLutype:
Liner Hanger PressLre hpsiK:3,775.0
f est HLutype:
Liner Hanger PressLre hpsiK:2,780.0
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 7.62 5.78 35.42 2,685.99 2,650.57
Cross Over 3 1/2 2.99 563 Wedge 1.27 2,687.26 2,685.99
144 Blank Liner 3 1/2 2.99 9.20 L-80 563 Wedge 4,484.49 7,171.75 2,687.26
Liner Pup Joint 3 1/2 2.99 9.20 L-80 563 Wedge 3.30 7,175.05 7,171.75
Landing Collar 3 1/2 8rd JHOBBS 1.80 7,176.85 7,175.05
Liner Pup Joint 3 1/2 2.99 9.20 L-80 8rd Wedge 2.96 7,179.81 7,176.85
1 Blank Liner 3 1/2 2.99 9.20 L-80 BTC Wedge 30.88 7,210.69 7,179.81
Float Collar 3 1/2 BTC Innovex 1.10 7,211.79 7,210.69
1 Blank Liner 3 1/2 2.99 9.20 L-80 BTC Wedge 30.75 7,242.54 7,211.79
Shoe 4 1/4 BTC Innovex 1.46 7,244.00 7,242.54
Page 1/1
Well Name: BRU 221-35
Report Printed: 12/18/2023
www.peloton.com
Cement
3.5" Liner cement
Type
Casing
Description
3.5" Liner cement
Cemented String
Liner 1, 7,244.00ftKB
Wellbore
221-35
Job
231-00132 BRU 221-35 Drilling, Drilling -
Drilling, 10/11/2023 06:00
Cementing Start Date
10/25/2023
Cementing End Date
10/25/2023
Top Depth (ftKB)
2,649.4
Cement Stages
Stage Number: 1
Description
3.5" Liner cement
Top Depth (ftKB)
2,649.4
Bottom Depth (ftKB)
7,244.0
Top Measurement Method
Volume Calculations
Pump Start Date
10/25/2023
Cement in Place At
10/25/2023
Final Circulating Pressure (psi)
1,330.0
Plug Bump Pressure (psi)
1,862.0
Full Return?
No
Returns During Job (%)
79
Volume to Surface (bbl)
9.0
Volume Lost (bbl)
53.4
Bump Plug?
Yes
Float Failed?
No
Pipe Reciprocated?
No
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) Tuned Tuned 3.82 10.50 30.0 30.0 4 HES
Lead Slurry Type I II Type I II 448 2.39 12.00 191.0 191.0 4 HES
Tail Slurry Type I II Type I II 122 1.24 15.30 26.0 26.0 3 HES
Displacement 6% KCL
PHPA mud
6% KCL
PHPA mud
9.65 75.5 75.5 4 HES
Post Job Calculations
Subtype Value
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 11/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 221-35
- PTD 223-077
- API 50-283-20193-00-00
FINAL LWD FORMATION EVALUATION LOGS (10/13/2023 to 10/23/2023)
EWR-M5, AGR, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-077
T38128
11/15/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.11.15
15:11:10 -09'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 11/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 221-35
- PTD 223-077
- API 50-283-20193-00-00
FINAL MUDLOGS - EOW DRILLING REPORTS (10/13/2023 to 10/23/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINT FILES (2” and 5” MD and TVD COLOR TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log
Drilling Dynamics Log
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-077
T38128
11/15/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.11.15
15:12:26 -09'00'
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
From:McLellan, Bryan J (OGC)
To:Jacob Flora
Cc:Donna Ambruz
Subject:RE: BRU 221-35 AOGCC 10-403 323-587 PTD 223-077 - CBL for approval
Date:Tuesday, November 7, 2023 11:35:00 AM
Attachments:image004.png
image005.png
Jake,
Hilcorp has approval to proceed with perforating per sundry 323-587.
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: Tuesday, November 7, 2023 10:21 AM
To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>
Cc: Donna Ambruz <dambruz@hilcorp.com>
Subject: BRU 221-35 AOGCC 10-403 323-587 PTD 223-077 - CBL for approval
Bryan,
Please see below and attached CBL. The cement looks to be at the LTP.
Let me know if you have questions-
Thanks,
Jake
From: Grant Levi <glevi@ake-line.com>
Sent: Tuesday, November 7, 2023 10:13 AM
To: Jacob Flora <Jake.Flora@hilcorp.com>
Subject: [EXTERNAL] BRU 221-35 Final CBL PDF in State Format
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
Grant Levi
Field Engineer
Alaska E-Line Services
42260 Kenai Spur HWY | PO Box 1481
Kenai, AK 99611
Office: (907) 283-7374
Cell: (907) 513-8005
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 herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
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):
7,244'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
FEDA029657
223-077
50-283-20193-00-00
Hilcorp Alaska, LLC
Proposed Pools:
9.2# / L-80
TVD Burst
2,656'
10,160psi
2,637'
Size
1,202,851'
2,851'
MD
See Attached Schematic
2,980psi
6,890psi
120'120'
2,851'
November 14, 2023
Tieback 3-1/2"
7,244'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 221-35CO 802
Same
6,904'3-1/2"
~2,174psi
4,593'
N/A
Length
LTP; N/A 2,651' MD/2,460' TVD; N/A, N/A
6,904'7,175'6,835'
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
Ot
66
t
2
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 11:16 am, Oct 31, 2023
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.10.31 10:42:31 -
08'00'
Noel Nocas
(4361)
323-587
MGR02NOV23 DSR-11/2/23
Perforate
BOPE test to 2500 psi. 48 hour notice to AOGCC.
CBL to AOGCC.
SFD 11/1/2023
10-404
~2,174psi
*&:
Brett W. Huber,
Sr.
Digitally signed by Brett W. Huber,
Sr.
Date: 2023.11.03 10:38:24 -08'00'11/03/23
RBDMS JSB 110723
Well Prognosis
Well Name:BRU 221-35 API Number:50-283-20193-00-00
Current Status:Gas Producer Permit to Drill Number:223-077
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: 2813 psi @ 6394’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2174 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 221-35 is the fifth of five grass roots wells drilled in the 2023 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 liner full of drilling mud, with the 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:
Fm Name MD Top MD Base Thickness TVD Top TVD Base
Beluga E 4205 4211 6 3911 3917
Beluga E1 4223 4228 5 3928 3933
Beluga E1 4233 4238 5 3938 3943
Beluga E1 4250 4255 5 3955 3960
Beluga E3 4368 4371 3 4070 4073
Beluga E5 4399 4407 8 4101 4109
Beluga E5 4417 4422 5 4119 4123
Beluga E5 4435 4438 3 4136 4139
Beluga E6 4495 4499 4 4195 4199
Beluga E6 4530 4534 4 4230 4234
Beluga E6 4538 4543 5 4238 4242
Beluga F 4600 4610 10 4299 4308
complete a CBL and
perforate multiple Beluga sands.
Well Prognosis
Beluga F4 4632 4638 6 4330 4336
Beluga F4 4647 4652 5 4345 4350
Beluga F4 4657 4662 5 4355 4360
Beluga F4 4666 4668 2 4364 4365
Beluga F4 4686 4691 5 4383 4388
Beluga F5 4714 4717 3 4411 4414
Beluga F5 4728 4733 5 4425 4429
Beluga F5 4735 4743 8 4431 4439
Beluga F6 4792 4798 6 4488 4493
Beluga F6 4810 4813 3 4505 4508
Beluga F6 4842 4848 6 4537 4543
Beluga F7 4855 4859 4 4550 4554
Beluga F7 4868 4878 10 4562 4572
Beluga F7 4908 4914 6 4602 4608
Beluga F7 4928 4933 5 4622 4626
Beluga F7 4946 4950 4 4639 4643
Beluga F7 4970 4978 8 4663 4671
Beluga F10 5021 5026 5 4713 4718
Beluga F10 5030 5033 3 4722 4725
Beluga F10 5037 5040 3 4729 4732
Beluga F10 5041 5044 3 4733 4736
Beluga F10 5050 5054 4 4742 4746
Beluga F10 5060 5074 14 4752 4765
Beluga G1 5101 5116 15 4792 4807
Beluga G2 5129 5134 5 4820 4825
Beluga G2 5162 5169 7 4852 4859
Beluga G2 5182 5189 7 4872 4879
Beluga G2 5214 5219 5 4904 4909
Beluga G5 5291 5296 5 4980 4985
Beluga H 5468 5470 2 5154 5156
Beluga H 5477 5481 4 5163 5167
Beluga H 5484 5492 8 5170 5178
Beluga H1 5516 5522 6 5202 5208
Beluga H2 5547 5571 24 5232 5256
Beluga H3 5603 5607 4 5288 5292
Beluga H4 5620 5629 9 5304 5313
Beluga H5 5681 5685 4 5365 5368
Beluga H5 5688 5692 4 5371 5375
Beluga H5 5698 5701 3 5381 5384
Beluga H11 5912 5928 16 5592 5607
Beluga H11 6034 6041 7 5712 5718
Beluga H14 6070 6077 7 5747 5754
Well Prognosis
Beluga I2 6288 6295 7 5961 5968
Beluga I2 6323 6327 4 5996 6000
Beluga I12 6712 6727 15 6379 6394
a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
b. Frac Calcs: Using 14.1 ppg EMW FIT at the surface casing shoe (0.733 psi/ft frac grad)
c. Shallowest Allowable Perf TVD = MPSP/(0.733-0.1) = 2174 psi / 0.633 = 3434‘ TVD
10. RDMO
11. Turn well over to production & flow test well
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
3,434' TVD is equivalent to about 3,716' MD SFD
Updated by CJD 10-31-2023
Current SCHEMATIC
Beluga River Unit
BRU 221-35
PTD: 223-077
API: 50-283-20193-00-00
PBTD = 7,175’ / TVD = 6,835’
TD = 7,244’ / TVD = 6,904’
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 TXP 6.875” Surf 2,851’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,651’ 7,244’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,656’
1
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,651’ 4.875” 6.540” Liner hanger / LTP Assembly
2 2,656’ 4.790” 6.340” Seal Stem
3 1,510’ 2.813” 3.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% / 50% Lead/Tail excess)
3-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
3
Updated by DMA 10-31-2023
PROPOSED
Beluga River Unit
BRU 221-35
PTD: 223-077
API: 50-283-20193-00-00
PBTD = 7,175’ / TVD = 6,835’
TD = 7,244’ / TVD = 6,904’
RKB to GL = 18.5’
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Bel E-I ±4,205’ ±6,727’ ±3,911’ ±6,394’ Proposed TBD
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 TXP 6.875” Surf 2,851’
3-1/2" Prod Lnr 9.2 L-80 HYD 563 2.992” 2,651’ 7,244’
3-1/2" Prod Tieback 9.2 L-80 HYD 563 2.992” Surf 2,656’
1
16”
7-5/8”
9-7/8”
hole
3-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,651’ 4.875” 6.540” Liner hanger / LTP Assembly
2 2,656’ 4.790” 6.340” Seal Stem
3 1,510’ 2.813” 3.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface (75% / 50% Lead/Tail excess)
3-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
2
3
Bel E-I
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.
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Wednesday, December 6, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
221-35
BELUGA RIV UNIT 221-35
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 12/06/2023
221-35
50-283-20193-00-00
223-077-0
N
SPT
2460
2230770 3500
0 3775 3725 3720
0 0 0 0
OTHER P
Guy Cook
10/27/2023
MITT post completion per procedure to 3500 psi. Chart recorder on the rig was currently calibrated.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:BELUGA RIV UNIT 221-35
Inspection Date:
Tubing
OA
Packer Depth
0 75 75 75IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC231027142836
BBL Pumped:1 BBL Returned:1
Wednesday, December 6, 2023 Page 1 of 1
9
9
9
9
9
9
9 9
9 9 9
9
9
9
*DVSURGXFHU
MITT
James B. Regg Digitally signed by James B. Regg
Date: 2023.12.06 10:14:56 -09'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Wednesday, December 6, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Guy Cook
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
221-35
BELUGA RIV UNIT 221-35
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 12/06/2023
221-35
50-283-20193-00-00
223-077-0
N
SPT
2460
2230770 2500
0 390 390 390
0 0 0 0
OTHER P
Guy Cook
10/27/2023
MIT-IA post completion to 2500 psi per procedure. The chart recorder was currently calibrated.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:BELUGA RIV UNIT 221-35
Inspection Date:
Tubing
OA
Packer Depth
0 2780 2775 2775IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitGDC231027143331
BBL Pumped:1 BBL Returned:1
Wednesday, December 6, 2023 Page 1 of 1
1-Gas producer
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 221-35
JBR 12/05/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
Good test, zero failures
Test Results
TEST DATA
Rig Rep:Jon Van EveraOperator:Hilcorp Alaska, LLC Operator Rep:Josh Riley
Rig Owner/Rig No.:Hilcorp 147 PTD#:2230770 DATE:10/16/2023
Type Operation:DRILL Annular:
250/3500Type Test:INIT
Valves:
250/3500
Rams:
250/3500
Test Pressures:Inspection No:bopAGE231018153345
Inspector Adam Earl
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5
MASP:
2434
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"P
#1 Rams 1 2 7/8 X 5"P
#2 Rams 1 Blind P
#3 Rams 1 2 7/8 X 5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8" & 2 1/1 P
Kill Line Valves 3 2 1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P2975
Pressure After Closure P1700
200 PSI Attained P20
Full Pressure Attained P87
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4 @ 2637
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P5
#2 Rams P5
#3 Rams P5
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
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, Sterling Beluga Gas Pool, BRU 221-35
Hilcorp Alaska, LLC
Permit to Drill Number: 223-077
Surface Location: 851' FSL, 642' FWL, Sec 26, T13N, R10W, SM, AK
Bottomhole Location: 522' FNL, 1962' FWL, Sec 35, 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 September 2023. 21
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.09.21 15:41:09
-08'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11.Well Name and Number:
Bond No.
3. Address: 6.Proposed Depth: 12. Field/Pool(s):
MD: 7,244' TVD: 6,906'
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): 97.8 15. Distance to Nearest Well Open
Surface: x-318582 y- 2626002 Zone-4 79.3 to Same Pool: 1448' to BRU 211-25
16. Deviated wells: Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 26.7 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120'
9-7/8" 7-5/8" 29.7# L-80 TXP 2,860' Surface Surface 2,860' 2,645'
6-3/4" 3-1/2" 9.2# L-80 Hyd 563 4,584' 2,660' 2,466' 7,244' 6,906'
Tieback 3-1/2" 9.2# L80 Hyd 563 2,660' Surface Surface 2,660' 2,466'
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 221-35
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 - 1056 ft3 / T 131 ft3
2434
83' FSL, 1261' FWL, Sec 26, T13N, R10W, SM, AK
522' FNL, 1962' FWL, Sec 35, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
851' FSL, 642' FWL, Sec 26, T13N, R10W, SM, AK AKA029657 / ADL 17599
6199
18. Casing Program: Top - Setting Depth - BottomSpecifications
3125
Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 952 ft3 / T - 182 ft3
LengthCasing
Conductor/Structural
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Drilling Manager
Monty Myers
10/11/2023
3936' to nearest unit boundary
Sean Mclaughlin
sean.mclaughlin@hilcorp.com
907-223-6784
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Tieback Assy.
Stratigraphic Test
No Mud log req'd: Yes No
No Directional svy req'd: Yes No
Seabed ReportDrilling Fluid Program 20 AAC 25.050 requirements
BOP SketchDrilling Program Time v. Depth Plot Shallow Hazard Analysis
Single Well
Gas Hydrates
No Inclination-only svy req'd: Yes No
Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal
No
No
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
8.15.2023
By Grace Christianson at 3:17 pm, Aug 15, 2023
Drilling Manager
08/15/23
Monty M
Myers
BJM 9/18/23 DSR-8/18/23
BOP test to 3500 psi, Annular test to 2500 psi
Submit FIT results to AOGCC within 48 hrs of performing test.
50-283-20193-00-00
-A.Dewhurst
20 SEP 23
223-077
A.Dewhurst 20SEP23($8JLC 9/20/2023
09/21/23
09/21/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.09.21 15:41:31 -08'00'
BRU 221-35
Drilling Program
Beluga River Unit
PTD
August 10, 2023
BRU 221-35
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 ..........................................................................................................14
12.0 Run 7-5/8” Surface Casing ......................................................................................................16
13.0 Cement 7-5/8” Surface Casing.................................................................................................19
14.0 BOP N/U and Test....................................................................................................................22
15.0 Drill 6-3/4” Hole Section ..........................................................................................................23
16.0 Run 3-1/2” Production Liner ...................................................................................................26
17.0 Cement 3-1/2” Production Liner .............................................................................................29
18.0 3-1/2” Liner Tieback Polish Run.............................................................................................32
19.0 3-1/2” Tieback Run, ND/NU, RDMO ......................................................................................33
20.0 Diverter Schematic ..................................................................................................................34
21.0 BOP Schematic ........................................................................................................................35
22.0 Wellhead Schematic.................................................................................................................36
23.0 Anticipated Drilling Hazards ..................................................................................................37
24.0 Hilcorp Rig 147 Layout ...........................................................................................................39
25.0 FIT/LOT Procedure.................................................................................................................40
26.0 Choke Manifold Schematic......................................................................................................41
27.0 Casing Design Information......................................................................................................42
28.0 6-3/4” Hole Section MASP .......................................................................................................43
29.0 Spider Plot w/ 660’ Radius for SSSV.......................................................................................44
30.0 Surface Plat (As-Built NAD27 & NAD83)...............................................................................45
Page 2 Version 0 August, 2023
BRU 221-35
Drilling Procedure
Rev 0
1.0 Well Summary
Well BRU 221-35
Pad & Old Well Designation BRU H Pad –Grassroots Well
Planned Completion Type 3-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7,244 MD / 6,906’ TVD
PBTD, MD / TVD 7,164’ MD / 6,827’TVD
AFE Number
AFE Drilling Days 25
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2434 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3125 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 97.8’(79.3 + 18.5)
Ground Elevation 79.3’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 0 August, 2023
BRU 221-35
Drilling Procedure
Rev 0
2.0 Management of Change Information
!!
!
D
$)
S013N010W
Beluga
River UnitA029657
BRU
214-26
BHL
H PAD Pad
BRU
221-35_SHL
BRU
221-35_TPH
BRU
221-35_BHL
ADL 17599
Sec. 26
Sec. 27
Sec. 35Sec. 34
Beluga River Unit
BRU 221-35
wp02
0410820
Feet
Alaska State Plane Zone 4, NAD27 ¯
Legend
$)BRU 221-35_BHL
!BRU 221-35_SHL
D BRU 221-35_TPH
!Other Surface Well Locations
Other Bottom Hole Locations
Well Paths
DNR_Leases
Oil and Gas Unit Boundary
Map Date: 9/19/2023
Page 4 Version 0 August, 2023
BRU 221-35
Drilling Procedure
Rev 0
3.0 Tubular Program:
Hole
Section
OD (in)ID (in)Drift
(in)
Conn
OD (in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 -
Surface
9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80 TXP 6890 4790 683
Prod
6-3/4”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
Cleanout 2-7/8”2.323 2.265”3.438”7.9 P-110 PH-6 16,896 16,082 194k
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks).
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5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area –this will not save the data entered, and will navigate to another data entry
tab.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out-of-scope work as NPT.
5.2 Afternoon Updates
x Submit a short operations update each day to kenaiciodrilling@hilcorp.com
5.3 Morning Update
x Submit a short operations update each morning by 7am in NDE –Drilling Comments
5.4 EHS Incident Reporting
x Notify EHS field coordinator.
1. This could be one of (3) individuals as they rotate around. Know who your EHS field
coordinator is at all times, don’t wait until an emergency to have to call around and figure
it out!!!!
a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855
2. Spills: Keegan Fleming: O:907-777-8477 C:907-350-9439
x Notify Drlg Manager
1. Monty M Myers: O: 907-777-8431 C: 907-538-1168
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com, and cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com, and
cdinger@hilcorp.com
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6.0 Planned Wellbore Schematic
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7.0 Drilling / Completion Summary
BRU 221-35 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 ~250’MD. Maximum hole angle
will be ~28 deg. and TD of the well will be 7,244’ TMD/ 6,906’ TVD, ending with 10 deg inclination left in
the hole. Vertical separation will be 1913 ft.
Drilling operations are expected to commence approximately October, 2023. The Hilcorp Rig # 147 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 2,860 MD / 2,645’ TVD and cemented to surface to ensure protection of any
shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface
are not observed, a cement evaluation log (CBL/VDL or temperature log for example) will be run to determine
TOC. Necessary remedial action will then be discussed with 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 to haul 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 well site
2. N/U diverter and test.
3. Drill 9-7/8”hole to 2,860’ MD. Run and cmt 7-5/8”surface casing.
4. ND diverter, N/U & test 11” x 5M BOP.
5. Drill 6-3/4” hole section to 7,244’MD. Perform Wiper trip.
6. Make cleanout run
7. POOH laying down drill pipe.
8. Run and cmt 3-1/2”production liner.
9. PU clean out assembly and RIH to clean out 3-1/2”to landing collar
10. Displace well to 6% KCL completion fluid.
11. POOH and LD clean out assembly.
12. RIH and land 3-1/2” tieback string in liner top.
13. N/D BOP, N/U temp abandonment cap, RDMO.
Reservoir Evaluation Plan:
Surface hole: GR + Res MWD
Production Hole: Triple Combo
Mud loggers from surface casing point to TD.
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the below AOGCC regulations and all
BLM regulations pertaining to Onshore Order No.1. If additional clarity or guidance is required on how
to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling of BRU 221-35. Ensure to provide
AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing.
x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment
will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation, we must test all BOP
components utilized for well control prior to the next trip into the wellbore. This pressure test will
be charted same as the 14 day BOP test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”
x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man
office.
x 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.
Regulation Variance Requests:
x 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.
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Summary of BOP Equipment and Test Requirements
Hole Section Equipment Test Pressure (psi)
9-7/8”x 21-1/4” x 2M Hydril MSP diverter Function Test Only
6-3/4”
x 11” x 5M Annular BOP
x 11” x 5M Double Ram
o Blind ram in btm cavity
x Mud cross
x 11” x 5M Single Ram
x 3-1/8” 5M Choke Line
x 2-1/16” x 5M Kill line
x 3-1/8” x 2-1/16” 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3500
(Annular 2500 psi)
Subsequent Tests:
250/3500
(Annular 2500 psi)
x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal
bottles).
x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency
pressure is provided by bottled nitrogen.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 48 hours notice prior to testing BOPs.
x Any other notifications required in APD.
Required BLM Notifications:
x 48 hours before spud. Follow up with actual spud date and time within 24 hours.
x 72 hours before casing running and cmt operations
x 72 hours before BOPE tests
x 72 hours before logging, coring, & testing
x Any other notifications required in APD
Additional requirements may be stipulated on APD and Sundry.
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Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov
Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
BLM
Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127
Email: aschoessler@blm.gov
Use the below email address for BOP notifications to the BLM:
BLM_AK_AKSO_EnergySection_Notifications@blm.gov
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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 RU Mud loggers on surface hole section for gas detection only. No samples required
9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.9 Mix mud for 9-7/8”hole section.
9.10 Install 5-1/2” liners in mud pumps.
x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes
with 5-1/2” liners.
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10.0 N/U 21-1/4” 2M Diverter
10.1 N/U 21-1/4” Hydril MSP 2M diverter System.
x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so
that knife gate opens prior to annular closure.
x NOTE: Ensure closing time on diverter annular is in line with API RP 64:
2..1.1.Annular element ID 20” or smaller: Less than 30 seconds
2..1.2.Annular element ID greater than 20”: Less than 45 seconds
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking.
x A prohibition on ignition sources or running equipment.
x A prohibition on staged equipment or materials.
x Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
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10.5 Rig 147 and estimated Diverter line orientation on BRU H Pad:
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11.0 Drill 9-7/8”Hole Section
11.1 P/U 9-7/8”directional drilling assy:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2”Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8”hole section to 2,860’MD/ 2,644’ TVD. Confirm this setting depth with the
geologist and Drilling Engineer while drilling the well.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate.
x Utilize Inlet experience to drill through coal seams efficiently.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 500’ or every couple days unless hole conditions dictate otherwise.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Adjust MW as necessary to maintain hole stability.
x TD the hole section in a good shale between 2750’ MD and 3000’ MD.
x Take MWD surveys every stand drilled (60’ intervals).
11.5 9-7/8”hole mud program summary:
Weighting material to be used for the hole section will be barite. Additional barite will be on
location to weight up the active system (1) ppg above highest anticipated MW. We will start
with a simple gel + FW spud mud at 8.8 ppg.
Pason PVT will be used throughout the drilling and completion phase. Remote monitoring
stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Depths Density Viscosity Plastic Viscosity Yield Point API FL pH
120-2,860’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0
System Formulation: Aquagel + FW spud mud
Product Concentration
FRESH WATER
SODA ASH
AQUAGEL
CAUSTIC SODA
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
X-TEND II
0.905 bbl
0.5 ppb
12-15 ppb
0.1 ppb (9 pH)
as needed
as required for weight
if required for <12 FL
0.1 ppb
0.02 ppb
11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16”conductor shoe.
11.7 TOH with the drilling assy, handle BHA as appropriate.
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12.0 Run 7-5/8”Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 7-5/8”casing running equipment.
x Ensure 7-5/8”TXP x CDS 40 XO on rig floor and M/U to FOSV.
x R/U fill-up line to fill casing while running.
x Ensure all casing has been drifted on the location prior to running.
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ float shoe bucked on (thread locked).
x (1) Joint with coupling thread locked.
x (1) Joint with float collar bucked on pin end & thread locked.
x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end.
x Install (1) centralizer, mid tube on thread locked joint and on FC joint.
x Ensure proper operation of float equipment.
12.5 Continue running 7-5/8”surface casing
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values
required to achieve this position.
x After making up several connections, use the torque required to M/U to base of triangle as
the M/U torque and continue running string.
x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the
event a top out job is needed.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
7-5/8” 29.7# TXP M/U torques
Casing OD Minimum Maximum Yield Torque
7-5/8”15,970 ft-lbs 19,510 ft-lbs 24,200 ft-lbs
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12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.7 Slow in and out of slips.
12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the
landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint
while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the
hanger.
12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly
landed out in the wellhead profile.
12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume.
Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor
losses closely while circulating.
12.11 After circulating, lower string and land hanger in wellhead again.
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13.0 Cement 7-5/8”Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
13.2 Document efficiency of all possible displacement pumps prior to cement job
13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded
correctly.
13.4 Pump 5 bbls spacer. Test surface cmt lines.
13.5 Pump remaining spacer.
13.6 Drop bottom plug. Mix and pump cmt per below recipe.
13.7 Cement volume based on annular volume + 75% lead open hole excess and 50% tail open hole
excess. Job will consist of lead & tail, TOC brought to surface.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
16”Conductor x 7-5/8”
casing annulus:
120’ x .16239 bpf =19.49 109.4
12.0 ppg LEAD:
9-7/8”OH x 7-5/8”Casing
annulus:
(2360’ –120’) x .03825 bpf x
1.75 =
149.94 841.9
Total LEAD:169.43 bbl 951.3 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(2860’- 2360’)x .03825 bpf x
1.5 =
28.69 161.1
15.4 ppg TAIL:
7-5/8”Shoe track:
80 x .04592 bpf =3.67 20.6
Total TAIL:32.36 bbl 181.7 ft3
TOTAL CEMENT VOL:201.79 bbl 1133.0 ft3
verified cement & displacement calcs. -bjm
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Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Displacement calculation:
2860’-80’ = 2780’x .04592 bpf = 128 bbls
13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes
become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to
pump out fluid from cellar. Have some sx of sugar available to retard setting of cement.
13.13 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 3.6 bbls.
x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be
prepared to run a temp log between 12 –18 hours after CIP.
x Be prepared with small OD top out tubing in the event a top out job is required. The
AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes
is 1.5”.
Lead Slurry (2360’ MD to surface)Tail Slurry (2860’ to 2360’ 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
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13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held.
13.15 R/D cement equipment. Flush out wellhead with FW.
13.16 Back out and L/D landing joint. Flush out wellhead with FW.
13.17 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff.
Run in lock downs and inject plastic packing element.
13.18 Lay down landing joint and pack-off running tool.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 ND 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 3500 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Land out test plug (if not installed previously).
x Test BOP to 250/3500 psi for 5/10 min.
x Test VBR’s with 3-1/2”and 4-1/2”test joints
x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint
x Ensure to leave side outlet valves open during BOP testing so pressure does not build up
beneath the test plug.
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 9.0 ppg 6% KCL PHPA mud system.
14.7 R/U mud loggers for production hole section.
14.8 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 6-3/4” Hole Section
15.1 Pull test plug, run and set wear bushing
15.2 Ensure BHA components have been inspected previously.
15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
15.4 TIH 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 driller’s console, Co Man office, Toolpusher office, and mud
loggers office.
Ensure fluids are topped off and adequate lost circulation material is on location in anticipation
of losses in hole section.
System Type: 9.0 ppg 6% KCL PHPA fresh water based drilling fluid.
Properties:
MD Mud
Weight Viscosity Plastic
Viscosity Yield Point pH HPHT
2,860’-7,244’9.0 –10.0 40-53 15-25 15-25 8.5-9.5 11.0
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System Formulation: 6% KCL EZ Mud DP
Product Concentration
Water
KCl
Caustic
BARAZAN D+
EZ MUD DP
DEXTRID LT
PAC-L
BARACARB 5/25/50
BAROID 41
ALDACIDE G
BARACOR 700
BARASCAV D
0.905 bbl
22 ppb (29 K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 18 YP)
0.75 ppb (initially 0.25 ppb)
1-2 ppb
1 ppb
15 - 20 ppb (5 ppb of each)
as required for a 9.0 –10.0 ppg
0.1 ppb
1 ppb
0.5 ppb (maintain per dilution rate)
15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth
TOC tagged on AM report.
15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
graph. AOGCC requirement is 50% of burst.7-5/8” 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.
Note: Offset field test data predicts frac gradient at the 7-5/8”shoe to be between 11 - 15 ppg
EMW. A 13.6 ppg FIT results in a 24 bbl kick tolerance volume while drilling with the planned
MW of 9.0 ppg and an assumed 0.5ppg kick intensity over maximum pore pressure.
15.14 Drill 6-3/4” hole section to 7,244’ MD / 6,906’ TVD
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate.
x Keep swab and surge pressures low when tripping.
x Make wiper trips every 1000’ unless hole conditions dictate otherwise.
x On the third wiper trip (around 5,100’ MD), trip back to the 7-5/8” shoe (LL from 224-24) to
split the hole section in half.
x Ensure shale shakers are functioning properly. Check for holes in screens on connections.
x Watch for lost circulation when drilling through Beluga D and E (3685’ -4266’ TVD).
x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10.
x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed
necessary.
x Take (3) sets of formation samples every 20’.
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15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8”shoe.
15.16 TOH with the drilling assy, standing back drill pipe.
15.17 LD BHA
15.18 RIH to TD, pump sweep, CBU and condition mud for casing run.
15.19 POOH LDDP and BHA
15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint.
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16.0 Run 3-1/2”Production Liner
16.1. R/U Parker 3-1/2”casing running equipment.
x Ensure 3-1/2”HYD 563 x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info .
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 3-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 3-1/2” production liner
3-1/2” 9.2# HYD 563 M/U torques
Casing OD Minimum Maximum Yield
3-1/2”2,400 ft-lbs 4,200 ft-lbs 7,100 ft-lbs
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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 3-1/2”Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
Section:Calculation:Vol (BBLS)Vol (ft3)
12.0 ppg LEAD:
7-5/8” csg x 4-1/2” drillpipe
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
7-5/8” csg x 3-1/2” liner
annulus:
200’ x .03402 bpf =6.80 38.2
12.0 ppg LEAD:
6-3/4” OH x 3-1/2” annulus:
(6744’ –2860’) x .03236 bpf x
1.4 =
175.97 988.0
Total LEAD:188.02 bbl 1055.7 ft3
15.4 ppg TAIL:
6-3/4” OH x 3-1/2” annulus:
(7244’- 6744’) x .03236 bpf x
1.4 =
22.65 127.2
15.4 ppg TAIL:
3-1/2” Shoe track:
80 x .00870 bpf =0.70 3.9
Total TAIL:23.35 bbl 131.1 ft3
TOTAL CEMENT VOL:211.37 bbl 1186.8 ft3
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Cement Slurry Design:
Lead Slurry (6744’ MD to 2660’ MD)Tail Slurry (7244’ to 6744’ 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
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.
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17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned
after bumping plug and releasing pressure.
17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight
17.17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS
nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the
pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be
enough to overcome hydrostatic differential at liner top).
17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while
picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to
wellbore clean up rate until the sleeve area is thoroughly cleaned.
17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for
reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns
and record the estimated volume. Rotate & circulate to clear cmt from DP.
17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer
received the required setting force by inspecting the rotating dog sub.
Backup release from liner hanger:
17.21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will
have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure
and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear
screws.
17.22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down
to the setting tool.
17.23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then
proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop
1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up
with workstring to release collet from the profile.
17.24. WOC minimum of 12 hours, test casing to 3500 psi and chart for 30 minutes.
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Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and
sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 3-1/2”Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per 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 3,500 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 H563 liner. Ensure any jewelry is
picked up per tally.
x Install chemical injection mandrel at ~1,500’ MD.
3-1/2” 9.2# HYD 563 M/U torques
Casing OD Minimum Maximum Yield
3-1/2”2,400 ft-lbs 4,200 ft-lbs 7,100 ft-lbs
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 3,500 psi and chart for 30 minutes. 48 hr notice required.
19.7 Test 7-5/8” x 3-1/2” annulus to 2,500 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
9-7/8”Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 –45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
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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
superseded by
updated plat
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30.0 Surface Plat (As-Built NAD27 & NAD83)
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!!"
#
-500
0
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Tr
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0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000
Vertical Section at 136.00° (1000 usft/in)
BRU 221-35 tgt2
BRU 221-35 tgt1
7 5/8" x 9 7/8"
3 1/2" x 6 3/4"
5 0 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 00 0
3 50 0
4 0 0 0
4 5 0 0
5 0 0 0
5 5 0 0
6 0 0 0
6 5 0 0
7 0 0 0
7 2 4 4
BRU 221-35 wp02a
Start Dir 3º/100' : 250' MD, 250'TVD
End Dir : 1140.3' MD, 1108.4' TVD
Start Dir 2º/100' : 3110.36' MD, 2868.26'TVD
End Dir : 3972.33' MD, 3683.86' TVD
Total Depth : 7244.01' MD, 6905.83' TVD
BRU_ST_A1_COAL
STERLING_B
STERLING_C
BELUGA_D
BELUGA_E
BELUGA_F
BELUGA_G
BELUGA_H
BELUGA_I
BRU_BELUGA_J
BRU_BELUGA_J6
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: BRU 221-35
79.30
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2626002.60 318582.63 61° 11' 1.0794 N 151° 1' 40.7971 W
SURVEY PROGRAM
Date: 2023-07-24T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2860.00 BRU 221-35 wp02a (BRU 221-35) 3_MWD+AX+Sag
2860.00 7244.01 BRU 221-35 wp02a (BRU 221-35) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3132.80 3035.00 3399.73 BRU_ST_A1_COAL
3339.80 3242.00 3618.53 STERLING_B
3493.80 3396.00 3778.12 STERLING_C
3684.80 3587.00 3973.28 BELUGA_D
3901.80 3804.00 4193.63 BELUGA_E
4265.80 4168.00 4563.25 BELUGA_F
4766.80 4669.00 5071.98 BELUGA_G
5129.80 5032.00 5440.58 BELUGA_H
5846.80 5749.00 6168.64 BELUGA_I
6424.80 6327.00 6755.55 BRU_BELUGA_J
6891.80 6794.00 7229.76 BRU_BELUGA_J6
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 221-35, True North
Vertical (TVD) Reference:As-Built RKB @ 97.80usft (HEC 147)
Measured Depth Reference:As-Built RKB @ 97.80usft (HEC 147)
Calculation Method:Minimum Curvature
Project:Beluga River
Site:BRU H-Pad
Well:BRU 221-35
Wellbore:BRU 221-35
Design:BRU 221-35 wp02a
CASING DETAILS
TVD TVDSS MD Size Name
2645.00 2547.20 2860.43 7-5/8 7 5/8" x 9 7/8"
6905.84 6808.04 7244.01 3-1/2 3 1/2" x 6 3/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 18.50 0.00 0.00 18.50 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD
3 1140.30 26.71 141.21 1108.40 -158.83 127.67 3.00 141.21 202.94 End Dir : 1140.3' MD, 1108.4' TVD
4 3110.36 26.71 141.21 2868.26 -848.96 682.44 0.00 0.00 1084.75 Start Dir 2º/100' : 3110.36' MD, 2868.26'TVD
5 3972.33 10.00 126.08 3683.86 -1045.50 865.67 2.00 -171.21 1353.41 BRU 221-35 tgt1 End Dir : 3972.33' MD, 3683.86' TVD
6 6744.01 10.00 126.08 6413.43 -1328.97 1254.63 0.00 0.00 1827.52 BRU 221-35 tgt2
7 7244.01 10.00 126.08 6905.83 -1380.10 1324.80 0.00 0.00 1913.04 Total Depth : 7244.01' MD, 6905.83' TVD
-1
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1
Dewhurst, Andrew D (OGC)
From:Sean McLaughlin <sean.mclaughlin@hilcorp.com>
Sent:Wednesday, September 20, 2023 08:34
To:Dewhurst, Andrew D (OGC)
Cc:McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC)
Subject:RE: [EXTERNAL] BRU 221-35 (PTD 223-077)
Attachments:BRU_221-35_wp02_AOGCC.pdf; BRU_221_35_wp02.xls
Andy,
Itappearswehadanoutdatedmaplayer.Ihaven’theardagoodexplanaƟonofwhythatisyet.Therevisedmappingis
aƩached.TheBHLofBRU221Ͳ35willremaininAKA29657.
Regards,
sean
From:Dewhurst,AndrewD(OGC)<andrew.dewhurst@alaska.gov>
Sent:Friday,September15,20233:52PM
To:SeanMcLaughlin<sean.mclaughlin@hilcorp.com>
Cc:McLellan,BryanJ(OGC)<bryan.mclellan@alaska.gov>;Davies,StephenF(OGC)<steve.davies@alaska.gov>;Guhl,
MeredithD(OGC)<meredith.guhl@alaska.gov>
Subject:[EXTERNAL]BRU221Ͳ35(PTD223Ͳ077)
Sean,
I’mcompleƟngthereviewofBRU221Ͳ35andhaveaquesƟonforyou.
x WouldyoupleasedoubleͲcheckontheADL/AKAleaseboundary?I’mnotseeingtheBHLcrossingoutsideofAKA
29657:
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
CAUTION:Externalsender.DONOTopenlinksorattachmentsfromUNKNOWNsenders.
2
Thanks,
Andy
AndrewDewhurst
SeniorPetroleumGeologist
AlaskaOilandGasConservaƟonCommission
333W.7thAve,Anchorage,AK99501
andrew.dewhurst@alaska.gov
Direct:(907)793Ͳ1254
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
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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 nogreater
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
BRU 221-35
STRLG-BELUGA GAS
223-077
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l
o
c
a
t
e
d
p
r
o
p
e
r
d
i
s
t
a
n
c
e
f
r
o
m
d
r
i
l
l
i
n
g
u
n
i
t
b
o
u
n
d
a
r
y
NA
6
We
l
l
l
o
c
a
t
e
d
p
r
o
p
e
r
d
i
s
t
a
n
c
e
f
r
o
m
o
t
h
e
r
w
e
l
l
s
Ye
s
7
Su
f
f
i
c
i
e
n
t
a
c
r
e
a
g
e
a
v
a
i
l
a
b
l
e
i
n
d
r
i
l
l
i
n
g
u
n
i
t
Ye
s
8
If
d
e
v
i
a
t
e
d
,
i
s
w
e
l
l
b
o
r
e
p
l
a
t
i
n
c
l
u
d
e
d
Ye
s
9
Op
e
r
a
t
o
r
o
n
l
y
a
f
f
e
c
t
e
d
p
a
r
t
y
Ye
s
10
Op
e
r
a
t
o
r
h
a
s
a
p
p
r
o
p
r
i
a
t
e
b
o
n
d
i
n
f
o
r
c
e
Ye
s
11
Pe
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
i
t
h
o
u
t
c
o
n
s
e
r
v
a
t
i
o
n
o
r
d
e
r
Ye
s
12
Pe
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
i
t
h
o
u
t
a
d
m
i
n
i
s
t
r
a
t
i
v
e
a
p
p
r
o
v
a
l
Ye
s
13
Ca
n
p
e
r
m
i
t
b
e
a
p
p
r
o
v
e
d
b
e
f
o
r
e
1
5
-
d
a
y
w
a
i
t
NA
14
We
l
l
l
o
c
a
t
e
d
w
i
t
h
i
n
a
r
e
a
a
n
d
s
t
r
a
t
a
a
u
t
h
o
r
i
z
e
d
b
y
I
n
j
e
c
t
i
o
n
O
r
d
e
r
#
(
p
u
t
I
O
#
i
n
c
o
m
m
e
n
t
s
)
(
F
o
r
s
e
r
v
NA
15
Al
l
w
e
l
l
s
w
i
t
h
i
n
1
/
4
m
i
l
e
a
r
e
a
o
f
r
e
v
i
e
w
i
d
e
n
t
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
NA
16
Pr
e
-
p
r
o
d
u
c
e
d
i
n
j
e
c
t
o
r
:
d
u
r
a
t
i
o
n
o
f
p
r
e
-
p
r
o
d
u
c
t
i
o
n
l
e
s
s
t
h
a
n
3
m
o
n
t
h
s
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
NA
17
No
n
c
o
n
v
e
n
.
g
a
s
c
o
n
f
o
r
m
s
t
o
A
S
3
1
.
0
5
.
0
3
0
(
j
.
1
.
A
)
,
(
j
.
2
.
A
-
D
)
Ye
s
18
Co
n
d
u
c
t
o
r
s
t
r
i
n
g
p
r
o
v
i
d
e
d
Ye
s
19
Su
r
f
a
c
e
c
a
s
i
n
g
p
r
o
t
e
c
t
s
a
l
l
k
n
o
w
n
U
S
D
W
s
Ye
s
20
CM
T
v
o
l
a
d
e
q
u
a
t
e
t
o
c
i
r
c
u
l
a
t
e
o
n
c
o
n
d
u
c
t
o
r
&
s
u
r
f
c
s
g
Ye
s
21
CM
T
v
o
l
a
d
e
q
u
a
t
e
t
o
t
i
e
-
i
n
l
o
n
g
s
t
r
i
n
g
t
o
s
u
r
f
c
s
g
Ye
s
22
CM
T
w
i
l
l
c
o
v
e
r
a
l
l
k
n
o
w
n
p
r
o
d
u
c
t
i
v
e
h
o
r
i
z
o
n
s
Ye
s
23
Ca
s
i
n
g
d
e
s
i
g
n
s
a
d
e
q
u
a
t
e
f
o
r
C
,
T
,
B
&
p
e
r
m
a
f
r
o
s
t
Ye
s
24
Ad
e
q
u
a
t
e
t
a
n
k
a
g
e
o
r
r
e
s
e
r
v
e
p
i
t
NA
25
If
a
r
e
-
d
r
i
l
l
,
h
a
s
a
1
0
-
4
0
3
f
o
r
a
b
a
n
d
o
n
m
e
n
t
b
e
e
n
a
p
p
r
o
v
e
d
Ye
s
26
Ad
e
q
u
a
t
e
w
e
l
l
b
o
r
e
s
e
p
a
r
a
t
i
o
n
p
r
o
p
o
s
e
d
Ye
s
27
If
d
i
v
e
r
t
e
r
r
e
q
u
i
r
e
d
,
d
o
e
s
i
t
m
e
e
t
r
e
g
u
l
a
t
i
o
n
s
Ye
s
28
Dr
i
l
l
i
n
g
f
l
u
i
d
p
r
o
g
r
a
m
s
c
h
e
m
a
t
i
c
&
e
q
u
i
p
l
i
s
t
a
d
e
q
u
a
t
e
Ye
s
29
BO
P
E
s
,
d
o
t
h
e
y
m
e
e
t
r
e
g
u
l
a
t
i
o
n
Ye
s
MP
S
P
=
24
3
4
p
s
i
,
B
O
P
r
a
t
e
d
t
o
5
0
0
0
p
s
i
(
B
O
P
t
e
s
t
t
o
3
5
0
0
p
s
i
)
30
BO
P
E
p
r
e
s
s
r
a
t
i
n
g
a
p
p
r
o
p
r
i
a
t
e
;
t
e
s
t
t
o
(
p
u
t
p
s
i
g
i
n
c
o
m
m
e
n
t
s
)
Ye
s
31
Ch
o
k
e
m
a
n
i
f
o
l
d
c
o
m
p
l
i
e
s
w
/
A
P
I
R
P
-
5
3
(
M
a
y
8
4
)
Ye
s
32
Wo
r
k
w
i
l
l
o
c
c
u
r
w
i
t
h
o
u
t
o
p
e
r
a
t
i
o
n
s
h
u
t
d
o
w
n
No
33
Is
p
r
e
s
e
n
c
e
o
f
H
2
S
g
a
s
p
r
o
b
a
b
l
e
NA
34
Me
c
h
a
n
i
c
a
l
c
o
n
d
i
t
i
o
n
o
f
w
e
l
l
s
w
i
t
h
i
n
A
O
R
v
e
r
i
f
i
e
d
(
F
o
r
s
e
r
v
i
c
e
w
e
l
l
o
n
l
y
)
Ye
s
H2
S
n
o
t
a
n
t
i
c
i
p
a
t
e
d
b
a
s
e
d
o
n
o
f
f
s
e
t
w
e
l
l
s
.
35
Pe
r
m
i
t
c
a
n
b
e
i
s
s
u
e
d
w
/
o
h
y
d
r
o
g
e
n
s
u
l
f
i
d
e
m
e
a
s
u
r
e
s
Ye
s
Ma
x
p
o
r
e
p
r
e
s
s
u
r
e
a
n
t
i
c
i
p
a
t
e
d
a
s
8
.
7
p
p
g
E
M
W
,
w
i
t
h
m
a
n
y
s
a
n
d
s
s
e
v
e
r
e
l
y
u
n
d
e
r
p
r
e
s
s
u
r
e
d
(
~
2
.
2
p
p
g
)
36
Da
t
a
p
r
e
s
e
n
t
e
d
o
n
p
o
t
e
n
t
i
a
l
o
v
e
r
p
r
e
s
s
u
r
e
z
o
n
e
s
NA
37
Se
i
s
m
i
c
a
n
a
l
y
s
i
s
o
f
s
h
a
l
l
o
w
g
a
s
z
o
n
e
s
NA
38
Se
a
b
e
d
c
o
n
d
i
t
i
o
n
s
u
r
v
e
y
(
i
f
o
f
f
-
s
h
o
r
e
)
NA
39
Co
n
t
a
c
t
n
a
m
e
/
p
h
o
n
e
f
o
r
w
e
e
k
l
y
p
r
o
g
r
e
s
s
r
e
p
o
r
t
s
[
e
x
p
l
o
r
a
t
o
r
y
o
n
l
y
]
Ap
p
r
AD
D
Da
t
e
20
-
S
e
p
-
2
3
Ap
p
r
BJ
M
Da
t
e
18
-
S
e
p
-
2
3
Ap
p
r
AD
D
Da
t
e
15
-
S
e
p
-
2
3
Ad
m
i
n
i
s
t
r
a
t
i
o
n
En
g
i
n
e
e
r
i
n
g
Ge
o
l
o
g
y
Ge
o
l
o
g
i
c
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
:
En
g
i
n
e
e
r
i
n
g
Co
m
m
i
s
s
i
o
n
e
r
:
Da
t
e
Pu
b
l
i
c
Co
m
m
i
s
s
i
o
n
e
r
Da
t
e
*&
:
JL
C
9
/
2
0
/
2
0
2
3
