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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
Date: 08/11/2023
To: Alaska Oil & Gas Conservation Commission
Petroleum Geology Assistant
333 W 7th Ave Ste 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 223-34
- PTD 223-041
- API 50-283-20188-00-00
Washed and Dried Well Samples (06/20/2023)
B Set (2 Boxes):
WELL
BOX
SAMPLE INTERVAL (FEET / MD)
BRU 223-34
BOX 1 OF 2
2930- 4340' MD
BRU 223-34
BOX 2 OF 2
4340' - 5690' MD
Please include current contact information if different from above.
2Z3-()L
1 �53
RECEIVED
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By Date:
AUG 11 2023
AOGCC
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: 08/08/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230808
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 223-34 50283201880000 223041 7/21/2023 AK E-LINE PERF
END_MPI 1-01 50029218010000 188037 7/22/2023 AK E-LINE PERF
Please include current contact information if different from above.
T37916
T37917
8/8/2023
BRU 223-34 50283201880000 223041 7/21/2023 AK E-LINE PERF
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.08
12:24:06 -08'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): Beluga River Unit
GL: 84.6' BF: N/A
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
23.
BOTTOM
16" X-56 120'
7-5/8" L-80 2,591'
4-1/2" L-80 6,099'
4-1/2" L-80 2,380'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
N/A
Oil-Bbl: Water-Bbl:
025694 0
7/23/2023 24
Flow Tubing
25
3454
N/A34540
1689' FSL, 2417' FEL, Sec 34, T13N, R10W, SM, AK
Choke Size:
Surface
Per 20 AAC 25.283 (i)(2) attach electronic information
12.6#
2,611
2,371'
Surface
84#
29.7#
120'
Water-Bbl:
PRODUCTION TEST
7/17/2023
Date of Test: Oil-Bbl:
Flowing
*** Please see attached schematic for perforation detail ***
Gas-Oil Ratio:
AMOUNT
PULLED
315415
315461
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud
log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing
collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
PACKER SET (MD/TVD)
Conductor
BOTTOMCASINGWT. PER
FT.GRADE CEMENTING RECORD
2621208
SETTING DEPTH TVD
2621602
TOP HOLE SIZE
CBL 7-14-23, Mudlogs, MWD (AGR, PWD, DDSR, EWR-M5, ADR, PCG)
N/A
N/A
N/A
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
315277 2619657
50-283-20188-00-00June 3, 2023
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
7/15/2023 223-041 / 323-360
N/A
BRU 223-34June 20, 2023270' FNL, 377' FEL, Sec 4, T12N, R10W, SM, AK
103.1'
Sterling - Beluga Gas Pool
A029656 / A029657
6,500' MD / 6,107' TVD
6,000' MD / 5,622' TVD
1294' FSL, 2457' FEL, Sec 34, T13N, R10W, SM, AK
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
Tieback Assy.Tieback
TUBING RECORD
L - 361 sx / T - 98 sx6-3/4"
9-7/8"
Driven
Surface L - 392 sx / T - 173 sx
12.6#
Surface
4-1/2"
SIZE DEPTH SET (MD)
2,600' MD / 2,371' TVD
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date perf'd or liner run):
2,600' 6,493'
Surface
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
2,611'
Surface
2,854'
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 3:20 pm, Aug 02, 2023
Completed
7/15/2023
JSB
RBDMS JSB 081423
GDSR-8/18/23
223-041 / 323-360
BRU 223-34
WCB 1-24-2025
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval 4,844 Bel F7 4,498'
3570' 3232'
3723' 3382'
3917' 3572'
4137' 3787'
4526' 4168'
5079' 4708'
5475' 5092'
6298' 5894
Bel I 1
6350' 5944'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Digital Signature with Date:Contact Email:cdinger@hilcorp.com
Contact Phone: 907-777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports.
Authorized Title: Drilling Manager
Formation Name at TD:
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
INSTRUCTIONS
Bel E
ST B1
Bel F
Bel I
ST C1
Bel D
Bel G
Bel H
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
No
NoSidewall Cores: Yes No
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Drilling Manager
08/02/23
Monty M
Myers
Updated by CJD 07-27-23
CURRENT SCHEMATIC
Beluga River Unit
BRU 223-34
PTD: 223-041
API: 50-283-20188-00-00
PBTD = 6,000’ / TVD = 5,622’
TD = 6,500’ / TVD = 6,107’
RKB to GL = 20’
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 USS-CDC 6.875” Surf 2,854’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,600’ 6,493’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,611’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 1,511’ 3.958” 4.500” Chemical Injection Sub
2 2,600’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
3 6,000’ Cement Retainer set 7/12/23
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface 40 bbls lead to surface
4-1/2” TOC @ 2875’, poor cement 4450-4692’, good cement 4700-6000’ (CBL 7-14-23)
Cement squeezed 71 bbls 15.8 # cement below coil tubing retainer at 6000’
6-3/4”
hole
2
1
Bel H9
Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Bel F7 4,844’ 4,856’ 4,498’ 4,510’ 12’ 7/21/2023 Open
Bel F7 4,871’ 4,877’ 4,524’ 4,530’ 6’ 7/21/2023 Open
Bel F7 4,944’ 4,958’ 4,644’ 4,609’ 14’ 7/20/2023 Open
Bel F7 4,971’ 4,985’ 4,622’ 4,636’ 14’ 7/20/2023 Open
Bel F10 5,059’ 5,071’ 4,708’ 4,719’ 12’ 7/20/2023 Open
Bel G3 5,170' 5,184' 4,816' 4,829' 14' 7/16/2023 Open
Bel G5 5,219' 5,235' 4,760' 4,879' 16' 7/16/2023 Open
Bel G6 5,318' 5,336' 4,959' 4,977' 18' 7/16/2023 Open
Bel H1 5,537' 5,542' 5,172' 5,177' 5' 7/16/2023 Open
Bel H1 5,550' 5,564' 5,184' 5,198' 14' 7/16/2023 Open
Bel H2 5,574' 5,599' 5,208' 5,232' 25' 7/16/2023 Open
Bel H4 5,669' 5,677' 5,300' 5,308' 8' 7/15/2023 Open
Bel H4 5,682' 5,688' 5,313' 5,319' 6' 7/15/2023 Open
Bel H4 5,691' 5,697' 5,321' 5,327' 6' 7/15/2023 Open
Bel H5 5,730' 5,740' 5,359' 5,369' 10' 7/15/2023 Open
Bel H5 5,745' 5,753' 5,374' 5,382' 8' 7/15/2023 Open
Bel H6 5,804' 5,814' 5,431' 5,441' 10' 7/15/2023 Open
Bel H8 5,824' 5,829' 5,451' 5,456' 5' 7/15/2023 Open
Bel H9 5,848' 5,853' 5,474' 5,479' 5' 7/15/2023 Open
Bel G3
Bel H2
Bel H4
Bel H5
Bel H6
Bel H8
Bel G5
Bel F10
Bel G6
Bel H1
coil cmt retainer 6,000’
tbg punch holes 6,040-6,044’
Bel F7
3
Activity Date Ops Summary
5/29/2023 Fire up moving equipment and let warm up, Remove handrails from rig floor from subbase. Mobe crane to lay down yard. R/U cranes and connect rigging to
derrick, PJSM, remove derrick from draworks skid and place on trailer, Secure and remove derrickmans doghouse to pass under. 17 A-frames and highlines at
C pad. Load drilling line spool on trailer with derrick. Remove Draworks skid. Set catwalk off of Betty White. Cranes lift subbase and set on second bed truck and
secure. Load pony walls one at a time on Betty White and transfer to C pad. Set pony walls in place on C pad. Set Iron Roughneck HPU in place. Bring in
subbase and cranes and set subbase on pony walls. Betty White P/U draworks and bring to C pad and set in place on subbase. Bring in derrick and take off
binders. P/U derrickmans doghouse and mount to mast, P/U Drilling line spool and set on Draworks skid. P/U derrick and set in place on draworks skid. Bed
truck take MP#1 and pull past where walkway jig goes. Betty White grabs Mud Pit #1 module and position in place. Set jig walkway and position MP #1 module.
Roughnecks connect lifting rams to derrick. Lift Iron Roughneck and install on rig floor. Tail roll MP #2 module and back into position. Betty White bring Pit #2
module from lay down yard. and set in position. Bring Top Drive F/ Barge landing and set aside on C-Pad. Continue placing rig modules Pit mod #3, Pump
House bubble, Generator module, Bleed Hydraulics and raise mast. Set Doghouse/ Water tank module and raise doghouse and set Boiler module in place. Lay
felt liner and mats for catwalk, spot in catwalk and raise ramp, organize pad build mud docks, hook up rig systems air water and electrical, spot in third party
shacks, hook up mud lines. Continue rigging up rig systems, work Barge (Polar Bear), stage equipment and continue rigging up, hang anti fall devices in derrick,
prep to spool up draw works and scope derrick.
5/30/2023 CCI set and secured office trailers on float trailers, then transported same to C pad. Hung windwalls on pits with crane. Pinned lower torque tube to upper
section and scoped up derrick. Stood poorboy degasser. Set office trailers and gen skid. Installed turnbuckles and T bar on torque tube, Wired in mud lab, wired
in office trailers and powered up. Set comm tower and scoped up, strung comm lines and Pason lines. Cont RU steam and water lines in pits. RU and transfered
topdrive to rig floor, attached to blocks. CCI welded landing ring to. conductor and installed 4" outlets on conductor. Set diverter adaptor on landing ring and
released wellhead rep. Set trailer sewer tanks in place with crane. Removed 1" extend frame extension mount from topdrive and replaced with 2", install service
loop and kelly hose, continue working on piping for office sewer tanks, finish pit inspection and prep to roll fluid through pits. Finish dressing top drive bails and
link tilt, install saver sub and clamps, N/U diverter assembly install starting head and spacer spool and T, Work Barge ( Lash 200) offload equipment and
transfer to location, take on water to pits and roll through every pit and gun lines.
5/31/2023 Dressed derrick board, set diverter annular, trimmed 7" off top of flow riser and installed on annular, tore down hopper #2 and cleared scale from jet, set 40'
connex, handy bermed rig footprint, repaired electric cord on rig HPU, brought in accessible mud product and staged on docks,. start installing diverter vent line.
Cont install diverter vent line and anchors, CCI setting bridge on main road in attempt to access J pad, cleaned up scrap felt and liner, installed gas
alarms/lights, sensors and control panel. Transported flow riser to weld shop for height adjustment on flow line outlet. Installed valves on conductor outlets. Work
on rig acceptance check list, change oil in agitators, trouble shoot COM slow reaction time, check/charge nitrogen pre charge on accumulator bottles, flow test
water well on C Pad, load and strap DP Prep to P/U DP and Rack Back. Service top drive and draw works, change saver sub and tighten clamps, check top
drive torque, pull rotary cover and free up seized up rotary lock, change oil in rotary table and replace rotary cover, install mouse hole in table f/ picking up DP.
6/1/2023 Installed remainder of BOP bolts in stack flanges, Quadco Rep calibrated all gas alarms and function tested, rig electrician replace video camera cables, put
koomey unit on line and function diverter system, tore down gen #1 exhaust for welding of flange, organized pad. Cont working on comm's, transported flow riser
to rig from weld shop, NU flow riser and flow line, chained off stack, installed kicker hyd ram on catwalk, PU and rack back stands 4 1/2" DP, CCI and TMC set
2nd bridge on main road and re-worked soft spots. Sent AOGCC 72 hr notice for diverter function test at 13:02 on 6-1-23 and BLM 72 hr notice at 13:23 on 6-1-
23. Continue P/U and racking back 4.5'' DP 80 stands of DP total and 8 stands of HWDP, move mud product off J pad and stage on D pad, Build wet dock in
CCI yard, Build spud mud. Continue building spud mud, service rig and top drive, change filters on floor motor, clean and organize conexs, perform general
maintenance, test mud lines to 2000 psi good, continue moving mud products off J pad, Offload Barge (Lash 200), organize location, transport equipment f/
barge landing.
6/2/2023 Calibrated draw works encoder, cont mixing spud mud, set upright water tank for cementing, set cement silo, transported jars and centrifuge to location,
functioned hole fill pump, installed glycol pump alarm for eaton brake, troubleshot and fixed the skate control for rig floor, functioned test pump. checked and
tightened hydraulic hoses and fittings on catwalk. BLM Rep Allie Schoessler waived witness of diverter function test this morni ng, 6-2-23 at 10:46. Checked and
tightened flange bolts on choke manifold, RU boiler and filled with water for start up, set centrifuge feed pump and centrifuge in pit mod #3, welder repaired gen
#1 exhaust flange, Pason Rep updated Tool Pushers base unit, cont offload mud product at rig from J pad and barge. Replaced bad light bulbs in pits, RU
centrifuge and feed pump, welder replaced bad floor plate hinge and repaired rotary table lock lever, troubleshot centrifuge feed pump. Spotted craned and spun
cement silo 180, set remaining wind wall on pits with crane spot in cuttings tank and Hurricane install magnets on top drive RPM sensor, stage up boiler, M/U
Jar stand and rack back. Continue with inventory and general maintenance, clean out 40' c can and inventory, change out valve on mix hopper, set up tiger tank
farm and continue moving mud product off J pad to D pad. Accepted Rig at 00:01 on 6-3-23.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 223-34
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00084 BRU 223-34 Drilling
Spud Date:
y
Sent AOGCC 72 hr notice for diverter function test at 13:02 on 6-1-23
6/3/2023 Set primary and secondary muster signs, pressure wash throughout the rig, set blockades and well on diverter signs, clean floor motor radiator, PU single DP jnt
and park in stack for diverter testing. AOGCC and Quadco Reps on location at 08:20. Function tested annular and knife valve with a joint of 4 1/2" DP in hole.
Verified annular holding by slacking off on blocks. Performed drawdown test of koomey unit. Measured vent line and outlet from sub base and stack. Quadco
Rep tested all audio/visual gas alarms. Function tested flow show and PVT audio and visual alarms. No issues. LD single jnt, re-wrapped service loop sock for
topdrive, installed pump part cabinet in pump room, sent cuttings chute and hardware to welder for fabrication, returned and installed on centrifuge. Cont
cleaning radiators, shut down camp gen and changed oil/filter, after restart lost comm's. Staged directional BHA on catwalk while waiting on IT in town to
establish comm's, removed and packed winter tarps from HPU skid, Comm's back at 14:15. PU and MU 9 7/8" Kymera and 6 3/4" mudmotor w/1.5 bend. Eased
in hole 2 stands HWDP and tagged bottom at 130'. PU 5' off bottom, MU topdrive and attempted to fill conductor with spud mud. Pressured up to 800 psi with no
returns, shut down and bled off. Racked back stand and checked/functioned topdrive IBOP's, MU topdrive and attempt to fill conductor. At 880 psi, pressure
dumped and motor started working. Filled conductor with 24.5 bbls, shut down and checked for leaks, no leaks. Racked back stand, PU and checked bit, all jets
clear. MU DM collar and scribed with an RFO of 65.94. MU EWR-M5 and TM HOC, plugged in and uploaded MWD. MU stand HWDP at 77', shallow pulse test,
wash down and spud well at 130', cont drilling from 130' to 201', 1 to 2K wob, 369 gpm-633 psi, 33 rpm-2600 ft/lbs on bott torque, 152 ft/hr ROP. Pulled up hole
racking back HWDP to 77'. PU 2 jnts NM flex DC's to 139'. Wash down on HWDP to 200'. Notified BLM of actual spud date/time along with 72 hr notice for
surface casing run and cementing. Resumed drilling 9 7/8" surface hole from 201' to 433', 400 gpm 1050 psi SPP, 40 rpm 4 k tq on bottom, WOB 8k, PUW 30k
SOW 30k Rot 30k. Continue Drilling 9 7/8'' Surface hole f/ 433' t/ 1010' 445 gpm 1250 psi SPP, 60 rpm 4k tq on bottom, 3-8k WOB, 40k PUW 40k SOW 40k
ROT, Distance to well plan 12.29' 11.14' High 5.19' Left @ 737'.
6/4/2023 Cont drilling surface hole from 1010' to 1072', Sliding wob 102K, 409 gpm-1125 psi, 7 psi diff, 230 ft/hr ROP. Made hook and found pump #1 weeping mud in
pod #2. Went to pump #2 and work pipe 30' off bottom while replacing wear plate and gasket on pod #2, pump #1. Cont drilling surface from 1072' to 1442'. Rot
wob 1-2K, 407 gpm-1108 psi, 65 rpm-4500 ft/lbs on bott torque, 100 to 130 ft/hr ROP. Sliding wob 1-2K, 409 gpm-1125 psi, 7 psi diff, 230 ft/hr ROP. MW 8.9/vis
191, ECD's at 10.0, BGG 1 unit. Got centrifuge feed pump up and running with no issues. Sent BLM 72 hr notice for initial BOP test at 11:09 on 6-4-23. CBU at
408 gpm-1194 psi, 65 rpm-5152 ft/lbs off bott torque. Flow check was static. Pulled first stand while CBU and racked back. Attempted to pull up hole on
elevators but immediately overpulled. MU topdrive and backreamed from 1378' to HWDP at 700'. 353 gpm-1041 psi, 65 rpm-6500 to 7800 ft/lbs off bott torque.
(we have not done any backreaming. prior to connections so as not to lose any inclination). At 700' pulled on elevators with no issues to jars at 360'. Serviced rig
and topdrive, replaced seal in liner wash pump on mud pump #1 and replaced o-ring on topdrive hyd hose on HPU. TIH on elevators from 360' to 1376', down wt
30K. At 1376' we set down 3 times. MU topdrive, filled pipe, washed/reamed down to 1378'. MU last stand, filled pipe, washed and reamed to bottom at 1442'.
Made hook and started 20 bbl hi-vis nut plug sweep down drill string. With sweep out the pipe resumed drilling ahead from 1442' to 1521'. Rot wob 1-2K, 408
gpm-1221 psi, 65 rpm-5320 ft/lbs on bott torque, 100 ft/hr ROP. Sliding wob 1-2K, 405 gpm-1210 psi, 10 psi diff, 250 ft/hr ROP. MW 8.9/vis 207, ECD's at 9.8
ppg, BGG 0 units. Continue Drilling 9 7/8'' Surface Hole f/ 1521' t/ 1934' 405 gpm 1330 psi 60 rpm 6400 tq on bottom PUW 55k SOW 40k ROT 48k, 7k WOB,
ECD 9.77 ppg, MW 8.9 ppg, Sweep back on time 10% increase in cuttings. Continue Drilling 9 7/8'' Surface Hole f/ 1934' t/ 2297' 405 gpm 1280 psi SPP 60
RPM 7k tq on bottom PUW 57k SOW 40k ROT 50k, 4-8k WOB, ECD 9.5 ppg MW 9 ppg, Sweep back on time no increase in cuttings, Distance from plan 5.15'
4.34' Low 2.78' Left.
6/5/2023 Cont drilling surface hole from 2297' to 2684'. Sliding wob 2K, 402 gpm-1304 psi, 16 psi diff, 240 ft/hr ROP. Rot wob 1K, 402 gpm-1298 psi, 63 rpm-7500 ft/lbs
on bott torque, 100 to 120 ft/hr ROP. MW 9.0/vis 123, ECD's at 9.6 ppg, BGG 1 unit. Gave AOGCC 48 hr notice for upcoming initial BOP test at 08:19 on 6-5-23.
Cont drilling from 2684' to TD at 2863' md/2598 tvd. Rot wob 7K, 400 gpm-1426 psi, 65 rpm-7650 ft/lbs on bott torque, 120 ft/hr ROP. At 2670'md/2434'tvd we hit
hard spot and ROP reduced to 8 ft/hr. Pumped 20 bbl nut plug sweep with no noticeable change in parameters. Increased wob from 18K to 22K, increased
pump rate to 520 gpm-2076 psi at 2710', sweep back 1 bbl late, 25% increase in cuttings. At 2738' we broke through hard spot and ROP increased to 120 ft/hr.
At 2782' into more hard drilling, ROP at 10 to 30 ft/hr. Broke through that at 2854' and ROP increased to 120 ft/hr again. CBU at 518 gpm-1892 psi, 70 rpm-8000
ft/lbs off bott torque. Flow check well static. POOH on elevators f/ 2863' t/ 357' No hole issues. Service rig an top drive, clean screens on mud pumps 50%
packed off. RIH f/ 357' t/ 2801' No issues hole took correct displacement, wash last stand to bottom no fill. Pump Hi Vis sweep around, sweep back on time no
increase in cuttings, flow check well static. POOH on elevators f/ 2863' t/ 700' No hole issues. Stand back and L/D BHA, L/D jars and jt of HWDP, L/D flex collars
t/ 208'.
6/6/2023 Plugged in and downloaded MWD data, LD remainder of smart tools, motor and bit. Kymera bit was in gauge and graded 1-1 on both pdc and cone sides. Total
K Rev's = 276M. Cleaned and cleared rig floor/catwalk of drilling BHA, staged casing equipment,. RU casing equipment and racked casing. RU fill up line and
staged centralizers on rig floor. Held PJSM with Parker Casing and rig crews. Inspected, PU and MU shoe track filling each joint individually to 128'. Stroked
shoe track and verified floats working properly (OK). Cont PU single in hole with 7 5/8" CDC 29.70# L-80 casing, filling on the fly, topping off every 10 jnts,
torqued to 15,500 ft/lbs. Ran total. 69 jnts (includes shoe track) to 2831' with no issues. Installed bail extensions on topdrive, PU landing joint with hanger, non-
rotating clamp installed, installed circ swedge and MU on stump. MU topdrive and broke circ at 2.4 bpm-110 gpm-71 psi. RD caasing tongs and removed from
rig floor, removed. non-rotating clamp, increased pump rate to 4 bpm-170 gpm-41 psi, pulled bushings, up wt 90K, dwn wt 50K, S/O and landed hanger on depth
on landing ring (20.95') twice with no issue. Casing shoe at 2854', top of FC at 2767'. PU 3' off seat. Cont to circulate staging up to 5 bpm-224 gpm-58 psi, layed
out ground tarp and spotted cementers trucks, staged plug launcher on rig floor, ran hardline to cellar cement line and 3" hose from pits to pump truck. Held
PJSM with rig team, cementers and CCI rig support. Landed hanger, loaded plugs in plug launcher, shut down rig pump, removed topdrive and circ swedge from
landing jnt. Installed plug launcher on stump, latched up elevators and installed cement hose to plug launcher. Verified upcoming wellhead orientation with
production Rep. Halliburton loaded lines with 5 bbls water, checked for leaks and flow path. Halliburton pressure tested lines at 475 psi low 3100 psi high, good
tests. Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 4.5 bpm 228-30 psi, dropped. bottom plug and pumped 169 bbls (392 sx) 12 ppg Type I II lead
cement at 4.5 bpm 30-203 psi, followed by 35 bbls (173 sx) 15.8 ppg Type I II tail cement at 3.5 bpm 203-173 psi. Halliburton dropped top plug, then displaced
with 9.0 ppg Spud Mud at 5 bpm 173-620. psi. Slowed pump to 2 bpm with 10 bbl to go. Did bump the plug at 122 bbls into displacement (calculated 127 bbls).
Held 1455 psi (FCP of 620 psi) for 3 minutes, bled off and floats held. Bled back 1 bbls to truck. Had 60 bbls of Spacer returns to surface. and 40 bbls lead
cement to surface. Added Bridge Maker LCM to lead cement at 2.4 pps. Mix water temp 48 deg. Pumped 75% excess on lead and 50% excess on tail. Lost 4
bbls throughout the job. Did reciprocate. CIP at 21:40 hrs, 6/6/2023. RD and released Halliburton. Drained & flushed stack of cmt to cellar through conductor
valve. Flushed cmt stand pipe manifold and flow line w/ water and blew down same. B/O LJ w/ WHR. Johnny Whacked the stack w/ black water. R/D buddy
bails and casing elevators. Crew change, held PTSM. Drained and vacuumed out diverter stack. Cont. hauling off excess spud and cleaning tank bottoms. N/D
diverter system - vent line, flow line, low riser, annular, knife valve, T, and spool. Removed diverter adapter flange from starting head as per WHR. Cleaned &
dressed hanger neck w/ HYD oil. ID of hanger neck - 7" OD - 11". P/U Cactus well head/ casing spool. Pretested well head T/5000 psi. M/U to starting head, run
in lock down studs and torqued to 650 ft lbs. to 650 ft lbs. Tested lower OD seals T/5000 psi for 10 min (ok). Obtained new RKB- 19.61'. Spotted crane, set BOP
stack in cradle w/ winch truck. Picked BOP stack from cradle, set in sub, and transferred to bridge cranes. Currently prepping BOP stack to set on wellhead.
Cont drilling surface hole from 1010' to 1072',
pq g
Continue Drilling 9 7/8'' Surface Hole f/ 1521' t/ 1934'
pgqp gp
PU and MU shoe track filling each joint individually to 128'. Strokedgg ggp gjy
shoe track and verified floats working properly (OK). Cont PU single in hole with 7 5/8" CDC 29.70# L-80 casing, filling on the fly, topping off every 10 jnts,gp p y( ) g
torqued to 15,500 ft/lbs. Ran total. 69 jnts (includes shoe track) to 2831' with no issues
gp g g
AOGCC and Quadco Reps on location at 08:20.
pg p g
Halliburton pressure tested lines at 475 psi low 3100 psi high, good pp p p ppgg
tests. Halliburton pumped 60 bbls 10.5 ppg Tuned Spacer at 4.5 bpm 228-30 psi, dropped. bottom plug and pumped 169 bbls (392 sx) 12 ppg Type I II lead p p ppg p p p pp p g p p () ppg yp
cement at 4.5 bpm 30-203 psi, followed by 35 bbls (173 sx) 15.8 ppg Type I II tail cement at 3.5 bpm 203-173 psi. Halliburton dropped top plug, then displacedp p y ( ) ppg yp p p pp p p g p
with 9.0 ppg Spud Mud at 5 bpm 173-620. psi. Slowed pump to 2 bpm with 10 bbl to go. Did bump the plug at 122 bbls into displacement (calculated 127 bbls). ppg p p p p p p g p p g p (
Held 1455 psi (FCP of 620 psi) for 3 minutes, bled off and floats held. Bled back 1 bbls to truck. Had 60 bbls of Spacer returns to surface. and 40 bbls leadp(
cement to surface.
6/7/2023 Attempted to lower BOP stack onto wellhead and offside bridge crane had hydraulic issue. RU wire rope slings to topdrive, removed bridge cranes from BOP lift
plate, S/O and installed BOP stack on wellhead. NU choke line to catwalk and kill line to mezz manifold. Installed hydraulic fittings on BOP stack. Cont offload
last of spud mud in ISO's and cleaning pits. Complete hammer up of choke and kill lines, installed drip pan and flow riser, installed 4 way chains on stack,
plugged in koomey lines, opened all ram doors and installed rams, bolted doors up, pinched door seals on lower ram doors, replaced door seals.Installed shock
hose on poorboy. degasser, AOGCC Rep and Quadco Rep on location early at 14:30, tested all audio/visual gas alarms with no issue, released Quadco Rep.
Function tested HCR's, opened annulus valve then installed test plug and test joint, trimmed cellar grating to fit either side of stack,. BLM Rep on location at
15:45 and did walk through/inspection of rig. Installed TIW and dart on test joint, flooded stack and surface lines to choke manifold, purged air, attempted shell
test, mud cross flanges leaking at 1500 psi, bled off and hammered up flange bolts. Attempt shell test, top of spacer spool leaked, bled off and hammered up
flange bolts. Flooded stack and purged air. CCI offloading 4 1/2" casing on H pad and drifting same. Tested annular at 250 low f/5 min, 2500 high for 10 min.
Tested BOPE at 250 psi low for 5 min/ high at 5000 psi for 10 min. Cont. building second batch of new 6% KCL PHPA mud. Test #5- Weep hole on UPR started
leaking, functioned UPR and attempted to retest. UPR - Failed. Moved forward with testing. Planning to replace UPR shaft seals on double gate and retest at the
end. Test #7- Fail/Pass due to air in blind ram cavities, functioned rams and purged out air - Pass. Currently changing out UPR shaft seals on double gate and
working on batch of new mud.
6/8/2023 Cleaned up hardware and replaced primary ram shaft seal and piston seals on upper ram. Buttoned up door, topped off BOP stack with water, installed test joint,
functioned upper rams multiple times to clear any air from ram cavity and to the check seals. Shell tested at 250 psi low and 5000 psi high with no issue, re-
tested upper rams at 250 psi low for 5 minutes, 5000 psi high for 10 minutes with BLM witness, good test. Pulled test plug, set wear ring, closed annulus valve,
flooded stack, RU test pump on mezz kill and pumped water to purge air, functioned and closed blinds. Pumped 70 gallons to achieve 3568 psi, held 30 min on
chart, bled back 70 gallons. RD test equipment, re-installed shock hose from catwalk to poorboy degasser, blew down kill line, BOP stack, choke line and choke
manifold to poorboy degasser to flush same with water. Staged BHA on catwalk and prepped to rack DP. Held PJSM with Sperry Reps and rig crew, PU 4 3/4"
motor with 1.5 bend, MU HDBS 5 blade PDC (GTD54DM) jetted with 5x11's, PU DM, PCG, ADR, PWD and TM collars. Plugged in and uploaded MWD data,
tallied 56 joints 4 1/2" DP on pipe racks during upload,. installed XO and RIH 1 stand HWDP. MU topdrive and shallow pulse tested smart tools. RIH 2 stands
HWDP, jars and 5 more stands HWDP to 716'. PU singled in hole 56 jnts DP from 716' to 2447'. Filled pipe at 2000'. Cont TIH on stands from 2447' to 2753',
MU topdrive, broke circ. P/U-64K S/O-44K. Washed/reamed down F/2753', tagged plugs/TOFC at 2766'. Drilled shoe track and 20' of new formation T/2863'.
CBU and had Mud loggers obtain cuttings sample at shakers (sand). P/U-64K S/O-44K ROT-52K GPM-230 SPP-1350 psi RPM-35 TQ-6K Diff- 55 psi MW-9.0
ppg ECD- 9.6 ppg. Held PJSM on displacement. Started displacing well over to new 9.0 ppg 6% KCL PHPA mud, GPM-255 SPP-1300 psi. Crew change, held
PTSM. Finished displacing well over to new 9.0 ppg 6% KCL PHPA mud. CBU x2. Racked back stand, put bit right outside of shoe. R/U testing equip. Flooded
lines and purged out air. Performed FIT to EMW of 13.8 ppg - 647 psi. Pumped in 15.25 gals Bled back 9 gals. R/D testing equip. Blow down across mud cross,
choke manifold, and vacuumed out MGS. Broke circ. Obtained SPR's. Currently staging up MP and prepping to directional drill 6.75" production hole as per
wp09.
6/9/2023 Drilled 6 3/4" hole from 2883' to 3118', initial parameters: wob 5K, 237 gpm-1300 psi, 40 rpm-5800 to 6100 ft/lbs on bott torque, 70 to 120 ft/hr ROP. Once smart
tools clear of casing shoe, increased to 256 gpm-1350 psi, 60 rpm-6500 ft/lbs on bott torque. screened up as mud. warmed up and sheared. Sliding wob 5K, 252
gpm-1463 psi, 97 psi diff, 50 ft/hr ROP. MW 9.1/vis 53, ECD's at 9.8 ppg, BGG 7 units, max gas 10 units. Cont drilling from 3118' to 3501', rot wob 1 to 5K, 256
gpm-1522 psi, 60 rpm-6865 ft/lbs on bott torque, 100 to 120 ft/hr ROP. Sliding, wob 1 to 8K, 256 gpm-1672 psi, 250 psi diff, 50 to 110 ft/hr ROP, MW 9.0/vis 63,
ECD's at 10.0 ppg, BGG 15 units, max gas 125 units. Cont. directional drilling 6.75" production hole F/3501'-T/3867'. P/U-77K S/O-54K ROT-59K GPM-255 SPP-
1430 psi RPM-60 TQ-8K Diff-183 psi WOB-3K Max gas- 345 units MW-9.2 ppg ECD-10.21 ppg. Shot on bottom survey. CBU GPM-255 SPP-1280 TQ-8.3K
RPM-60. Obtained new SPR's. Flow checked - static. Crew change, held PTSM. Pulled wiper trip, POOH on elevators F/3867'-T/2813' w/ no issues. P/U-68K
S/O-46K. Calculated hole fill = 5.8 bbls Act = 6.9 bbls Diff = 1.1 bbls over. Serviced rig - Greased crown, blocks, TD, DWKS, brake linkage, drive shaft, and IR.
Cleaned screens on both MP's. Checked both pulsation dampeners and saver-sub (ok). Static loss rate = 0. RIH on elevators F/2813'-T/2807' w/ no issues,
washed last stand to bottom w/ no fill. Calculated pipe displacement = 18.3 bbls Act = 17.5 bbls Diff = .8 bbls under. Broke circ. Staged up MP. Pumped 25 bbl
Hi-Vis sweep w/ walnut & condet. Sweep came back on time w/ a 20% increase in cuttings. Resumed directional drilling 6.75" production hole F/3867' to current
depth of 3930'. P/U-77K S/O-54K ROT-59K GPM-247 SPP-1320 psi RPM-60 TQ-7.6K Diff-76 psi WOB-3K Max gas- 104 units MW-9.2 ppg ECD-10.3 ppg.
Distance to well plan: 12.38' 11.75' Low 3.91' Right.
6/10/2023 Cont drilling 6 3/4" hole from 3930' to 4205'. Rot wob 1-2K, 247 gpm-1313 psi, 64 rpm-7614 ft/lbs on bott torque, 85 ft/hr ROP. MW 9.2/vis 58, ECD's at 10.2
ppg, BGG 38 units, max gas 246 units. Reduced pump rate on down strokes of drill string. Cont drilling from 4205' to 4300'. Rot wob 1 to 9K, 257 gpm-1710 psi,
65 rpm-7209 ft/lbs on bott torque, 25 to 55 ft/hr ROP. At 4224' md/3890' tvd while drilling ahead, flow dropped from 17% to 0%, quickly reduced pump rate to
166 gpm, flow came back 6%, 7%, 11% to 12% at 150 gpm. Cont to drill ahead, rot wob 2 to 9K, 166 gpm-989 psi, 65 rpm-7360 to 7700 ft/lbs on bott torque, at
4228' flow is back steady and stable at 12%. Little to no loss. Lost 13 bbls. Crept pump rate up to 176 gpm-957 psi. Made hook at 4238' cont drilling ahead. Rot
wob 6-7K 174 gpm-1097 psi, 65 rpm-7650 to 8000 ft/lbs on bott torque, 16 to 52 ft/hr ROP, MW 9.2/vis 58, ECD's 10.0 ppg, BGG 28 units, max gas 81 units.
Cont creep pump rate up to 192 gpm-1130 psi. At 4265' md/3930.5' tvd flow dropped from 11% to 6%, reduced pump rate to 164 gpm-923 psi and cont drilling
ahead, rot wob 6K, 65 rpm-7800 ft/lbs on bott torque. At 4270' flow dropped to 0%. Cont drilling ahead 14 ft/hr, flow 1-3%. At 4270' flow went to 0%. but hole
staying full, slight returns at times. Cont to drill ahead at 150 gpm-798 psi, 0 wob, 65 rpm-8500 ft/lbs torque, 23 ft/hr ROP. Fluid started dropping in hole so
running hole fill pump getting 8 to 9% return flow. Started building LCM pill. Rot wob 5-6K, 21 ft/hr ROP down to 10 ft/hr and stand drilled down to 4300'.
Backreamed up hole from 4300' to 4268' and started LCM pill down drill string. Pill consisted of baracarb 5, baracarb 25, steelseal 50 and barafiber fine at 80
ppb. Cont to backream up hole from 4268' to 4235', spotted pill outside bit at 149 gpm-749 psi, 35 rpm-7400 to 8200 ft/lbs off bott torque. Total lost thus far =
525 bbls. With pill in place pulled up hole on elevators from 4235' to 2818' with no issues, up wt 90K, Hole full and getting 7 to 9% return flow on trip tank during
trip. Took 34.5 bbls over on hole fill during trip. CCI filling pre-mix pit with water. Build volume in pre-mix pits and pit module #2 while monitoring loss rate with
trip tank. Initial rate at 36 bph. Current loss rate = 15.12 bph. Serviced rig, changed out saver sub on TD. Changed out light in derrick and inspected all others.
Changed out shaker screens. to all API 80's. Loaded out strapped & tallied 4.5" JFE lion liner onto trailers on H- Pad. Crew change, held PTSM. Finished 300
bbl batch of mud in pits 3-5. Cont. building 300 bbl batch in pre-mix tanks and LCM pill in PP while monitoring loss rate with trip tank. Current loss rate = 9.46
bph. Losses for the last 12 hrs = 256. Distance to well plan: 11.20' 10.30' Low 4.40' Right.
Cont drilling 6 3/4" hole from 3930' to 4205'.
Drilled 6 3/4" hole from 2883' to 3118',
6/11/2023 Cont building 300 bbls 6% KCL surface volume in pre-mix pits, monitored fluid loss on trip tank. Initial rate at 9.4 bph, at 14:00 4 bph. Eased in hole one stand
and MU topdrive putting bit outside surface casing. Rolled mud pump at 68 gpm to ensure BHA was clear, no issues, cont TIH on elevators from 2880 to 3861'
at 20 to 30 ft/min getting some displacement, dwn wt 44K. At 3861' filled pipe. then cont ease in hole at 20 to 30 ft/min, dwn wt 54K, to 4233'. No sign of LCM
scab at 4224'. MU topdrive on last stand, filled pipe, washed down from 4233' to 4300' at 92 gpm-540 psi, 20 rpm-7000 ft/lbs off bott torque. 6% flow. Saw a
pump pressure and differential pressure. increase from 4265' to 4280' (LCM scab) that reduced once below 4280'. At 4300' PU 4' and cont to circ at 96 gpm-537
psi, 20 rpm-7883 ft/lbs off bott torque, staged up to 160 gpm-845 psi, shut down and made hook. Resumed drilling 6 3/4" hole from 4300' to 4352', 2 to 6K wob,
156 gpm-1060 psi, 60 rpm-8291 ft/lbs on bott torque, 7 to 90 ft/hr ROP, 0% to 4% return flow. Were able to get surveys during last two connections, but PWD
communication in and out. Cont. drilling F/4352'-T/4483'. P/U-90K S/O-55K ROT-68K GPM-160 SPP-1210 psi TQ-8.5K RPM-60 Flow- 0-5% WOB-3/5K Diff-
316 psi Max gas 1 unit MW- 9.1 ppg ECD- 9.2 ppg. POOH and racked back 5 stds due to lack of surface volume (310 bbls) F/4483'-T/4170'. P/U-97K S/O-54K.
At 4170' spotted a 25 bbl - 80 ppg LCM pill consisting of Baracarb 5 12 ppb, Baracarb 50 12 ppb, Steelseal 50 10 ppb, Bara Fiber fine 6 ppb, Vanguard fine 10
ppb, along w/ our 20 ppb of back ground LCM. POOH on elevators F/4170'-T/2819' (7-5/8" casing shoe) w/ no issues. Cal hole fill = 9.25 bbls Act = 13.43 bbls
Diff = 4.18 bbls over. Cont. batching up new 3% KCL PHPA mud to rebuild mud volume system and monitoring hole on TT. Initial static loss rate = 25 bph. Crew
change, held PTSM and weekly safety meeting w/ rig crew. Cont. batching up new 3% KCL PHPA mud to rebuild mud volume system, building another 25 bbl -
80 ppb LCM pill, and monitoring hole on TT. Current static loss rate = 12 bph. Lost 903 bbl to the hole during the last 12 hrs. Distance to well plan: 9.67' 8.59'
Low 4.44' Right.
6/12/2023 Cont building 3% KCL mud in pre-mix tanks while monitoring well on trip tank. At 06:00 loss rate at 14.8 bph. At 14:00 loss rate at 10.8 bph. Built a total of 1190
bbls. Losses from 06:00 to 14:00 = 112 bbls. Eased in the hole one stand from 2819' to 2877', MU topdrive to flush BHA and ensure we could circulate.
Pressure went to 1000 psi before getting pump shut down. Bled off and made numerous attempts rattling string, rotating left and right, with DP pressure at 0-100-
300-500 psi,. inside and outside casing shoe with no luck. Notified Drilling Engineer, decision made to POOH LD smart tools. Drill string had sat 15.5 hrs static
with no circulating inside casing. POOH from 2877' to BHA at 716'. Up wt 64K. Calc hole fill = 20.6 bbls, actual hole fill = 41.6 bbls. Racked back HWDP and
jars, LD NM DC's due to having only one lift sub. Plugged in and down loaded MWD data. LD smart tools. DM collar and mud motor packed off with LCM. Clean
up rig floor, stage spare motor. M/U 6.75" BHA #3 - RR PDC bit, spare 1.5 motor w/ float, flex collars, and XO. RIH T/156', tested motor (ok). Cont. RIH w/ 6.75"
BHA #3 F/156'-T/2995' at 20 fpm. Filled pipe GPM-69 SPP-305 flow- 0-5% P/U-56K S/O-48K. Cont. RIOH w/ 6.75" BHA #3 F/2995'-T/3867' at 20 fpm. Filled
pipe GPM-68 SPP-331 flow- 0-4% P/U-77K S/O-56K. Cont. RIOH w/ 6.75" BHA #3 F/3867'-T/4170' at 20 fpm. P/U-80K S/O-59K Cal pipe displacement = 80.52
bbls Act = 25.1 bbls Diff = 55.42 bbls. Washed/Reamed F/4170'-T/4483'. Seen multiple tight spots at 4265', 4285'-4294', 4302'-4312', and 4371'. P/U-80K S/O-
59K ROT-64K GPM-102 SPP-562 psi Flow-4/5% TQ-5.3K RPM-20. Obtained new SPR's w/ BHA #3. Drilled ahead F/4483' to current depth of 4513'. P/U-80K
S/O-59K ROT-64K GPM-160 SPP-863 psi Flow-6% TQ-8.4K RPM-60 MW-9.0 ppg max gas 11 units.
6/13/2023 Drilled F/ 4513' T/ 4542' into Beluga F Formation, WOB 1-2K, GPM 160, SPP 913 psi. RPM 60, TQ on Bottom 7844 to 8680 ft/ lbs. Flow 5% to 6%, BGG 11
units, Max Gas 66 units. Backreamed a couple of times slowly, Flow dropped to 0%, Backreamed uphole F/ 4542' T/ 4168' GPM 154 SPP 700 psi. Pumped 22
BBL LCM Pill GPM 92 SPP 345 psi. Monitored well and POOH F/ 4168' T/ 3858' observed flow coming from well. M/U TD and pump out of hole while pulling F/
3858' T/ 2812'. Build mud volume for pit system with 3% KCL 9.0ppg PHPA drilling mud. Initial loss rate @ 15:30 = .5 bph. Lost rate before POOH @ 18:00 =
3.93 bph. BLM and AOGCC have waived witness of weekly BOPE Test. POOH F/2812'-T/BHA #3. Racked back HWDP & jar std. L/D flex collars, motor, and
PDC bit. Bit grade - 1-1. Hole fill = Calculated = 19.44 bbls Act = 33.11 bbls Diff = 13.67 bbls. Cleaned & cleared rig floor. P/U & M/U cement BHA - BHA #4. RR
6.75" Tri-cone bit w/ no jets, bit sub w/ float, stabilizer, XO, HWDP, and Jar std, RIH F/566'-T/1500' at 20 fpm. Crew change, held PTSM. Contacted Pason due
to PVT issues. Rebooted Pason hard drive remotely (ok). M/U cement manifold w/ FOSV, 5' pup, and head pin while filling pipe. R esumed RIH F/1500'-T/2840'.
Filled pipe. P/U-56K S/O-46K GPM-60 SPP-71 psi Flow-4%. RIOH F/2840'-T/3397'. Lost Pason communications again. Contacted Pason IT, re-located antenna
on doghouse roof, rebooted hard drive, and got Pason back up and running. Filled pipe, P/U-65K S/O-51K GPM-59 SPP-99 psi Flow-4%. Cont. RIOH on
elevators F/3397' to current depth of 4090'. Lost 108 bbls over the last 12 hrs.
6/14/2023 Cont. RIH on elevators F/ 4090' T/ 4212' and fill pipe. PUW 65K SOW 51K. R/U cementers before cleaning up hole T/4542' from LCM pill and pumping cement
with Bridge Maker. Discuss events with all parties and plans of pumping cement before RIH and inducing losses. Wash F/ 4212' T/ 4539' GPM 168 SPP 350psi.
CBU and flow check well (Well giving back 15 BBLs in 15 Minutes and volume slowing down). Discuss results with ODE. Agree to pull T/ 4212' and pump
cement pill as planned. PUW 80K SOW 59K. POOH F/ 4539' T/ 4212' Calculated displacement 2.1 BBLs, Actual displacement 7.64 BBLs. Hole gave back 5.54
BBLs over calculated displacement. Quadco Rep calibrated and tested all Gas Alarms. R/U HES Cementers. Pump 5 BBLs of H2O to flood lines and pressure
test 750 psi. low 3300 psi. high. Pump 25 BBLs of 15.8ppg Cement with Bridge Maker and chase with 52 BBLs of 9.0ppg 3% KCL. Pump pressure reached 225
psi with 52 BBLs into. displacement, Shut pumps down with 1 BBL left in pipe. Had return flow until 28 BBLs into displacement then return flow dropped to 0 and
remained at 0 until pumping complete. CIP at 12:02 pm. Confirm no pressure and break out cement standpipe hose, head pin, 5' pup and floor valve. POOH F/
4212' T/ 3838' M/U Top Drive and pull T/ 3810' and circulate 20 BBL cement contamination sweep through string and back out to surface W/ 2X BU. GPM 300
SPP 450 psi. Wait for cement to reach 70Bc and monitor well on trip tank. Build drill fluid volume in anticipation of losses. Total losses F/ 05:00 T/ 17:00 179
BBLs. RIH F/ 3810' T/ 4148' on elevators PUW 79K SOW 58K, Wash and Ream cement plug GPM 164 SPP 300psi RPM 45 TQ 6-6.5K F/ 4148' T/ 4535' CBU
while reciprocating and rotating GPM 166 SPP 320psi RPM 45 Max gas 66 units. Flow check - Initial flow rate = 75 bph. Flow slowed to .5 bph over 1 hr & 10
min. (ballooning). During washing/reaming, and circ. pumped away 120 bbls. During the flow checking, well gave back 66 bbls of the 120 pumped away. POOH
F/4535'-T/2791'. Initially POOH on elevators. At 3588' pumped OOH T/2791' due to swabbing. GPM-60 SPP-78 psi Flow 0-1% max gas 2 units. Performed 10
min flow check at the shoe. Initial flow after pumping OOH =1.25 bph. Final = .3 bph. POOH of elevators F/2791'-T/cementing BHA. Racked back HWDP, and
jar std. L/D Tricone bit, bit sub, and stab. Bit graded 1-1 w/ plugged nozzle. Pulled wear ring. R/U line to fill and monitor IA. R/U testing equip. Flooded stack,
mud lines, and choke manifold w/ water. Purged out air. Performed shell test. Started performing weekly BOP test as per BLM & AOGCC regulations. Annular -
250 Low/2500 High and BOP -250 Low/3500 High for 5/10 min. BLM & AOGCC have both waved witness. Losses over last 24 hrs. = 295 bbls.
6/15/2023 Continue weekly BOPE test as per BLM & AOGCC regulations with 4-1/2" Test Joint. Annular - 250 Low/ 2500 High and BOPE - 250 Low/ 3500 High for 5/10
min. BLM & AOGCC have both waived witness. Total of 2 Fail/ Passes on low test of Manual Kill & Manual Choke valves. Rig down and Blow down all
equipment from testing. Pull Test plug and install 9" ID Wear Ring. P/U & M/U 6-3/4" Directional Drilling BHA #5 and RIH, Bit, Motor, Scribe offset, DM, PCG and
ADR collars, PWD and TM collar with 2 flex collars. Program MWD and shallow test tools after first stand of HWDP. Cont. M/U BHA T/ 716'. Continue RIH with
BHA #5 with 4-1/2" 16.60# S-135 CDS40 Drill Pipe from derrick F/ 716' T/ 2818'. Filled pipe and CBU before entering open hole. P/U-60K S/O-56K GPM-82 SPP-
376 psi Flow-7%. Changed out grabber box dies. RIOH F/2818'-T/3854' at 20-30 fpm w/ no issues. CBU at 3854' to break gel strengths and freshen up mud in
the hole. Staged up mud pump. GPM- 56/93 SPP-334/578 psi Flow-5/9% Max gas-12 units. Cont. RIOH F/3854'-T/4484' w/ no issues. Obtained survey @ 4484'.
Mad passed F/4484'-T/4542' @ 200 fph. P/U-76K S/O-55K ROT-70K GPM-176 SPP-969 psi RPM-60 Flow-10% MW-9.05 ppg ECD-9.69 ppg Max gas-35 units.
Crew change, held PTSM. Drilled ahead 6.75" production hole F/4542' to current depth of 4732'. P/U-89K S/O-61K ROT-71K GPM-179 SPP-1270 psi RPM-60
WOB-9K Flow-13% ROP-60 MW-9.05 ppg ECD-9.8 ppg Max gas-330 units. Distance to well plan: 12.44' 11.66' Low 4.33' Right. Over last 24 hrs. lost 158 bbls
to the hole.
Continue weekly BOPE test as per BLM & AOGCC regulations with 4-1/2" Test Joint
Drilled F/ 4513' T/ 4542' into Beluga F Formation
6/16/2023 Drill 6-3/4" Production Hole F/ 4732' T/ 4919'. Fingerprint first four connections with flow % dropping. GPM 180 SPP 1307psi WOB 5-8K TQ 8.2K PUW 93K
SOW 60K ROT 72K Max Gas 75 units. M/W in 9.05ppg M/W out 9.1ppg ECD 9.8ppg. Drill 6-3/4" Production Hole F/ 4919' T/ 5042'. GPM 220 SPP 1550 to
1700psi WOB 5-11K TQ 8.3 to 9.8K PUW 100K SOW 58K ROT 74K Max Gas 398 units. M/W in 9.1ppg M/W out 9.1ppg ECD 10.2ppg. Pump 25 BBL 9.0ppg Hi-
Vis sweep @ 5042' Sweep came back 44 BBLs late with 50% increase in cuttings. GPM 77 to 253 SPP 420 to 1900psi. Cont. drilling 6-3/4" production hole
F/5042'-T/5188'. P/U-101K S/O-59K ROT-74K GPM-215 SPP-1307 psi WOB-5-12K TQ-10K Max Gas 397 units. MW-9.1 ppg ECD-10.2 ppg. Average loss rate
= 48-60 bph. Obtained new SPR's. Started batching up new mud in premix tanks. Crew change, held PTSM. Cont. drilling 6-3/4" production hole F/5188' to
current depth of 5388'. P/U-100K S/O-58K ROT-74K GPM-227 SPP-1530 psi WOB-10-12K TQ-9.5K Max Gas 205 units. MW-9.15 ppg ECD-10.1ppg. Distance
to well plan: 7.53' 7.08' Low 2.56' Right Over last 24 hrs. lost 891 bbls to the hole.
6/17/2023 Drill 6-3/4" Production Hole F/ 5388' T/ 5440' MD 5175' TVD. GPM 225 SPP 1400 to 1550psi WOB 5-11K TQ 8.3 to 10.4K PUW 109K SOW 58K ROT 76K Max
Gas 207 units. M/W in 9.15ppg M/W out 9.2ppg ECD 10.05ppg. Bleed off well with 21 BBLs returned from ballooning and monitor. Static. POOH F/ 5440' T/
4915' on elevators. PUW 111K SOW 54K. First 10 stands pulled, hole fill was not calculated. Lined up and pumped out of hole with correct hole fill. Line up well
on trip tank to monitor well. .5 BPH loss. Grease and inspect Crown, Blocks, Top Drive, Draworks, Drive shaft, Iron Roughneck and clean mud pump suction
screens that were 90% packed off. Replace pilot control check valves for top drive grabber. box open and close lines. Replace Saver Sub ID: 2.375" OD: 5.4"
OL: 9". Pump out of hole with 6-3/4" drilling assembly F/ 4915' T/ 3617' PUW 87K SOW 56K. Top Drive showing hydraulic dripping. Found a pin holed hydraulic
hose that is connected to the grabber box. Built a new hose and replaced same. Function test was good. Pump out of hole with 6-3/4" drilling assembly F/ 3617'
T/ 2814' Inside 7-5/8" Casing PUW 64K SOW 64K. Blow down Top drive and standpipe hose to connect Geo Span. Last 12 hour losses: 133 BBLs. Cont.
POOH on elevators F/2814'-T/185'. Racked back HWDP. Calculated Disp. = 34.72 bbls Act Disp. = 55.81 bbls Diff = 21.09 bbls over. L/D flex collars. Down
loaded MWD data. R/U Geo-Span in sub. L/D MWD tools. Milked mud motor, inspected PDC bit and verified offset. P/U directional BHA #6 w/ Geo-Tap tools.
Uploaded data to MWD tools. Tested Geo-span T/1937 psi (ok). Crew change, held PTSM. Loaded nukes and P/U flex collars. RIH out of derrick w/ remainder
of BHA #6. Filled pipe and shallow tested MWD tools (ok). Rig service- Greased crown, blocks, TD, IR, DWKS, brake linkage, and drive line. Installed clamp on
TD HYD line. Cont. RIH w/ directional BHA #6 F/1061'-T/2854'. @ 40-50 fpm. Filled pipe at the surface casing shoe. RIOH F/2854'-T/3360'. Broke circ. Filled
pipe. Calculated Pipe Disp. = 62.22 bbls Act Disp. = 49.68 bbls Diff = 12.54 bbls loss. Started Mad Passing F/3380' at 200 fph. Current depth of 3475'. P/U-
72K S/O-53K ROT-57K GPM-219 SPP-1031 psi RPM-60 TQ-7.3K MW-9.05 ppg Max gas 125 units. Distance to well plan: 2.28' 2.18' High .66' Left. Over the
last 12 hrs. we lost 155 bbls to the hole.
6/18/2023 Cycle pumps and downlinks as per Halliburton Directional, Troubleshoot PWD-FTWD insert on Geo-Tap and attempt to change choke size on Geo Span with no
success. POOH T/ remove Geo-Tap and install PWD. POOH F/ 3477' T/ BHA' PU 72K SO 55K Lay down two flex collars, Remove sources and download data.
Calculated hole fill 24.67 BBLs Actual hole fill 32.83 BBLs. Lay down Geo-Tap, P/U PWD plug in and Program MWD tools. Shallow pulse test GPM 203 SPP
600psi. PJSM, Install sources, P/U Flex Collars & RIH with HWDP & Jars from derrick. Continue RIH with 6-3/4" Directional BHA #7 F/ 740' T/ 2845' filling pipe
every 1500'. Calculated displacement 52.46 BBLs Actual displacement 43.72 BBLs PU 65K SO 55K. Blow down top drive and Geo-Span and rig down Geo-
Span from mud line. Total losses last 12 hours 32 BBLs. Serviced Rig- Greased crown, TD, IR, blocks, DWKS, wash pipe, drive shaft, brake linkage, and
cleaned both MP suctions. Monitored loss rate on TT = .5 bph. RIH F/2845'-T/3470'. Calculated pipe Disp. = 63.44 bbls Act = 48.74 bbls Diff =14.7 bbls. Mad
Passed OH F/3470'-T/4017'. P/U-78K S/O-47K ROT-62K GPM-204 SPP-953 psi Flow-14% RPM-60 TQ-8.2K Max gas -24 units MW-9.1 ppg ECD-9.7 ppg.
Crew change, held PTSM and weekly safety meeting w/ rig crew. Cont. Mad Passing F/4017'-T/4295'. P/U-78K S/O-47K ROT-62K GPM-203 SPP-973 psi Flow-
14% RPM-60 TQ-8.3K Max gas -11 units MW-9.1 ppg ECD-9.7 ppg. Flow checked. Cont. RIOH on elevators F/4295'-T/5442'. Worked through tight spot F/4800'-
T/4817' on elevators (Claystone). Broke circ. Staged up pump to break gels. Pumped 25 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back 12 bbls late, w/
a 40 increase in cuttings. Resumed drilling ahead F/5540' to current depth of 5565'. P/U-110K S/O-62K ROT-80K GPM-220 SPP-1630 psi Flow-16% RPM-60
TQ-9.8K WOB-5/6K Diff-373 psi Max gas -323 units MW-9.15 ppg ECD-10.0 ppg. Lost 93 bbls to the hole over the last 12 hrs.
6/19/2023 Drill 6-3/4" Production Hole F/ 5565' T/ 5784' MD. GPM 235 SPP 1400 to 1755psi WOB 10K TQ 10.2K PUW 111K SOW 61K ROT 78K Max Gas 800 units.
M/W in 9.2ppg M/W out 9.2ppg ECD 10.15ppg. SPRs @ 5597' MD 5250' TVD. MP #1 SPM 30 PSI 387, MP #2 SPM 29 PSI 410. Drill 6-3/4" Production Hole F/
5784' T/ 6000' MD. GPM 210 SPP 1500 to 1765psi WOB 12K TQ 10 - 12K PUW 120K SOW 58K ROT 79K Max Gas 217 units. M/W in 9.2ppg M/W out
9.25ppg ECD 10.1ppg. Cont. directional drilling 6.75" production hole F/6000'-T/6248'. P/U-127K S/O-62K ROT-83K GPM-210 SPP-1700 psi RPM-60 WOB-12K
TQ-12K Diff-350 psi Flow-11% Max gas 294 units MW-9.15 ppg ECD-10.0 ppg. Start building an additional 300 bbls of new mud due to losses increasing. Crew
change, held PTSM. Cont. directional drilling 6.75" production hole F/6248' to current depth of 6371'. P/U-127K S/O-64K ROT-85K GPM-201 SPP-1825 psi
RPM-60 WOB-12K TQ-11.7K Diff-380 psi Flow-9% Max gas 88 units MW-9.05 ppg ECD-9.9 ppg. Distance to well plan: 19.18' 18.34' High 5.63' Left Losses
to hole over last 24 hrs. = 1419 bbls.
6/20/2023 Drill 6-3/4" Production Hole F/ 6371' T/ 6500' MD 6107' TVD. GPM 205 SPP 1895psi WOB 15 to 17K TQ 10.6K PU 131K SO 67K ROT 89K Max Gas 90 units.
M/W in 9.1ppg M/W out 9.15ppg ECD 9.85ppg. Pumping out of hole F/ 6500' T/ 6179' PU 125K GPM 200 SPP 1300 to 1600psi Pulling at 60 FPM. Pump 25
BBL 50PPB LCM Pill at 72 GPM W/ SPP 347psi. PU 125K SO 65K, Max gas 65 units. POOH on elevators F/ 6179' T/ 5500' with no issues. PU 115K SO 60K
Calculated hole fill 4.2 BBLs Actual hole fill 7.69 BBLs. Confirm BHA clear by pumping through BHA with no pressure increases. Rig Service: Line up trip tank
and observe 2 BPH losses statically. Grease & inspect Crown, Blocks, Top Drive, Draworks, Drive Shaft, Brake Linkage and Iron Roughneck. Make up Top
Drive and CBU @ 5500' md while rotating and reciprocating. GPM 209 SPP 1200psi TQ 10K ECD 9.8 Max Gas 60 units Loss rate at 20 BPH while pumping. PU
110K SO 60K ROT 77K. RIH F/ 5500' T/ 6500' MD 6107' TVD Calculated displacement 18.3 BBLs Actual displacement 38.14 BBLs Obtain new SPRs @ 6500'
MD 6107' TVD MW 9.05ppg MP#1 15 SPM 256psi MP#2 15 SPM 250psi. Pump 25 BBL Hi-Vis sweep STS sweep came back 28 BBLs late with 60% increase
in cuttings. Pump out of hole F/6500' T/ 3277' GPM 200 SPP 1100psi 55 FPM. PU 69K 45K Calculated hole fill 21 BBLs Actual hole fill 68.56 BBLs. Pump out of
hole F/3277' T/ 2841' GPM 200 SPP 1100psi 55 FPM Calculated hole fill. Slip & Cut 22 wraps/ 105' of drilling line while monitoring well on trip tank. (Well initially
gained 1.2 BBLs in 15 minutes then the well became static the following 45 minutes). Continue T/ POOH F/ 2841' T/ 741' @ 30 FPM T/ BHA #7. Pulled 5 without
pump and swabbing was observed. Decision was continue pumping out of hole @ 100 GPM, SPP 390psi pulling @ 30' FPM. POOH and stand back 8 stands of
HWDP, L/D Jars, One joint of HWDP and both Flex Collars. Remove Sources and download MWD. Losses over the last 24 hours is 482 BBLs.
Drill 6-3/4" Production Hole F/ 5565' T/ 5784' MD
Drill 6-3/4" Production Hole F/ 5388' T/ 5440' MD
Drill 6-3/4" Production Hole F/ 4732' T/ 4919'.
Drill 6-3/4" Production Hole F/ 6371' T/ 6500' MD
6/21/2023 Complete Download of the MWD data. L/D TM collar, PWD, CTN, Stabilizer, ALD, ADR, PCG and DM. Break bit from mud motor, milk motor and L/D. Bit
graded 1-1-BT-N-X-I-PN-TD. Service and Inspect Blocks, Top Drive, Draworks, Brake Bands, Brake Linkage, Drive Line and Gear Box. PJSM for rigging up
casing equipment and running 4-1/2" Liner. R/U Casing equipment as per Parker TRS. Layout Shoe, Float Collar and Landing Collar joints and clean
connections for Baker-Lok. Function Test Casing equipment. PJSM after crew change, P/U and Baker-Lok Shoe Track and function test Float equipment. Good.
Continue RIH F/ 97' T/ 3863' with 4-1/2" 12.6# L-80 Range II JFELION Liner as per approved tally. Filling pipe on the run and topping off every 10 Jts. P/U
SLZXP LTP, RIH and inspect as per Baker rep. Load Zanplex. RIH with 1 std of 4.5" DP to 3966'. Circulate 1 liner volume at 200 GPM, 168 PSI, 6% flow with
minimal to no losses. Max gas= 53 units. Cont. RIH with 4 1/2" liner on 4.5" DP F/3966' T/4525' while drifting stds out of derrick filled pipe and attempted to
break circulation observing packed off pump at idle 1.5 BPM, 280 PSI no flow. Worked pipe up to 4481' seeing pressure fall off to 107 PSI and flow increase to
6%. CBU staging pumps up to 176 GPM, 152 PSI, 11% flow, Max gas= 3658 units. Worked pipe F/4525' T/4463' during circulation. Cont. RIH F/4525' T/6381'
filling pipe and breaking circulation for 500 stks every 10 stds. Drifting stds out of derrick. P/U single, 10' and 15' pup RIH T/6436', M/U last stand to top drive
and attempted to wash down-Packed off. Worked pipe down and up with no issues and still wasn't able to achieve circulation. R/B stand and attempted to pull
up hole pulling 50K over rig away. P/U last std and worked pipe F/6436' T/6461' maintaining 200-300 PSI on SPP. Pressure started to drop and slight returns
were observed at surface. Was able to get full returns at 73 GPM, 242 PSI, 6% flow. Cont. to work pipe and stage pumps up to 140 GPM, 301 PSI, 9% return
flow. Cont. working or way down F/6461' T/6497' slowly, slightly packing off until 6490' was achieved. No issues F/6490' T/6497'. CBU at 140 GPM, 305 PSI,
12% flow with 15 BPH loss rate. Max gas=4275 units. Staged pumps up to 176 GPM, 342 PSI, 13% flow with same loss rate. Attempted 200 GPM and loss rate
increase to 75 BPH, Slowed pumps back down to 176 GPM and loss rate healed back to 15 BPH. P/U and M/U cement head and hoses. Came back on with
pumps and staged to 220 GPM, 365 PSI, 15% flow with a 24 BPH loss rate.
6/22/2023 Tag bottom at 6500' with cement head move liner up two feet and park. PJSM with all parties involved for cementing 4-1/2" Liner. Close upper and lower IBOP
and close TIW on cement head. Open block valve to cuttings tank and Pump 5 BBLs of water to purge lines. Close block valve to cuttings tank and perform
pressure test of cement lines T/ 250psi low, set kick outs at 1500psi. good test. pressure up to 5000psi high. Good test. Set Kick outs at 1500psi. and pump 30
BBLs 10.5ppg Spacer followed by 120 BBLs of. 12ppg Lead cement followed by 22 BBLs of 15.3ppg Tail cement. Close TIW on cement head and wash cement
across top of cement head with water to cuttings tank. Close block valve to cuttings tank open TIW on cement head drop drill pi pe wiper plug and. pump 10
BBLs water followed with 9.1ppg mud from rig pumped by HES total displacement pumped was 95.5 BBLs with no indication of bump. Pumped another 4.5 BBls
(100 BBLs Total) with no bump and went to secondary release of Liner Top Packer. No indication of hanger. setting. worked left hand torque and held with
grabber box. Worked Pipe up and down and seen indication of hanger setting. P/U 7' and rotating right lowered down and seen dog sub torque against set
screws on Packer. Did this two more times and pressured. up drill pipe to 500psi. Pulled stinger up to connection, Released and bled off pressure and L/D
cement head. Screwed stand 41 into stump, pressured up to 500psi and pulled up releasing stinger. Marked pipe and rotated and reciprocated BU X2 at 10
BPM with 425psi. Total of 81 BBLs lost during job. POOH and L/D 10' pup, 15' pup and E-Kelly that were between stands 40 and 41. POOH and observe
sheared HRD-E and dog sub. Break stinger in half and L/D. Drain BOPE and M/U stack washer to E-Kelly and wash BOPE stack with black water. P/U and
break down cement head. Remove all unneeded equipment from rig floor. Remove Wear Ring and Install test plug with 4-1/2" Test Joint. R/U test equipment for
weekly test of BOPE and purge entire system. Shell Test T/ 3500psi. Perform weekly BOPE Test with 4-1/2" Test Jt. Testing Bag to 2500 PSI, 2 7/8" x 5"
Upper/Lower VBR, Blinds, Manual/HCR Choke and Kill, all choke manifold valves to 3500 PSI.1 FP on test #4 due to mis-valve alignment. Quadco
representative calibrated and tested all gas alarms. R/D testing equipment. Pull test plug and install wear ring. Blow down all surface lines and change out wash
pipe. P/U polish mill assembly and RIH on 4.5" stds of DP F/surface T/2613' tagging LTP with upper polish mill at 2600' with 5K down. Polish PBR at 81 GPM,
30 PSI, 5 RPM, 4-5K TQ. Increased to 40 RPM and reamed up and down 3 times. Increase to 60 RPM and pull out of LTP. Displace well over from 9.2 PPG
KCL to CI Water at 295 GPM, 230 PSI, 40 RPM, 4.3K TQ. Pumped 22 BBL spacer. Dumped 22 BBLS of spacer and 6 BBLS of interface. Perform Negative test
for 30 min= good. Clean shaker bed and trough. POOH L/D 4.5" DP F/2600' T/539'. CCI sucking nerf balls through pipe and doping threads before installing
thread protectors.
6/23/2023 Continue POOH and lay down drill pipe F/ 539' and L/D Polish mill assembly. RIH W/ pipe out of derrick with mule shoe & run 8 stands of HWDP and 33 stands
of drill pipe T/ 2578' circulate pipe volume of Corrosion Inhibited water through string. Monitor well & POOH L/D drill pipe & HWDP F/ 2578'. Removing pin
protectors on the rack. Pulling nerf balls through with vac truck suction, Re-doping both connections & installing thread protectors then placing pipe in pipe tubs.
P/U 5', 10' & 15' drill pipe pup jts and flush and L/D. R/U testing equipment for testing Liner Lap and 4-1/2" Liner. Purge system and Test T/ 3500psi. for 30
charted minutes. Good Test. 2.7 BBLs pumped in. 2.7 BBLs bled back to trip tank. Pull wear ring. Brush and wash wellhead with wash tool as per wellhead
representative. R/U TRS equipment & remove all equipment not needed on rig floor. P/U bullet seal assembly and RIH with 4.5", 12.6#, L-80, JFE-Lion tubing
F/Surface T/1108', P/U chem Injection Mandrel and R/U spooler, sheave and control line. P/T control line to 2500 PSI no leaks. Cont RIH with 4.5", 12.6#, L-80,
JFE-Lion tubing F/1108' T/1924 installing 2 SSB per JT. Cont. RIH with 4.5", 12.6#, L-80, JFE-Lion tubing F/1924' T/2587', PU=35K SO= 29K. Pick up joint
#205 and RIH to no-go. Tagged 8' high 3 times with 5-10K down. L/D joint and installed XO. P/U joint 205 and pumped down at 1 BPM, 11% flow no pressure.
Eased down passing previous spot and observed flow stop. Shut down and tagged 22' in on joint 205. L/D joint #'s 205,204 and 203. P/U pup joint ( 9.77', 3.75',
4.76', 4.76', 4.76'). P/U joint 203 and RIH. P./U hanger and terminated and installed injection line into hanger. P/T to 2500 PSI= good. Lowered hanger through
stack tagging high again. R/U cement line and pumped down 1 BPM, observing seals engage and pressure increase to 100 PSI. Opened IA and bled all
pressure off. Landed hanger and pressured back up to 200 PSI to verify seals engaged. Hanger landed with 20K hanging off, 1.71' off NO-GO and WLEG depth
of 2611'. Pressure test TBG hanger seals to verify good prior to setting hanger-good, Rotate landing Jt 6 times to the left engaging locks on hanger. Pull to 65K
(40K over up weight) verifying hanger locks engaged. Back out landing jt with 17 turns to the right and L/D Jt. Perform test on TBG hanger seals to 5000 PSI-
good.
6/24/2023 R/U testing equipment to perform MIT on Tbg. & IA. Purge all lines of air. Pump 1.9 BBLs into Tbg for a pressure of 3650psi. Hold for 30 charted minutes. Good
test and bleed off 1.7 BBLs back to trip tank. Line up on 7-5/8" X 4-1/2" IA & pump 1.4 BBLs in with. a pressure of 3700psi. and hold for 30 charted minutes.
Good Test. Bleed back 1.3 BBLs to trip tank. AOGCC waived witness during phone call and BLM waived witness from initial notice in e-mail. Install 4" type "H"
TWC. Flush Baraclean with CI water through all mud lines including mud pumps, Pop off lines, Kelly hose & Gas buster, Follow with Baracarb with CI water then
blow down all lines. N/D riser, flow line, Koomey lines, Choke line, Manual choke valve on mud cross, Remove pull tongs, crossover subs, mousehole and
everything from rig floor. R/D all three vendor shacks & start rigging down both mud pumps. N/D BOPE , Remove spacer spool to fit on BOPE carrier, Install Dry
Hole Tree, Continue cleaning mud tanks, Transferring fuel out of fuel tank into Fuel Cell. Test hanger void, Hanger neck seals and dry hole tree T/ 5000psi.
Good Test. Cleaning mud tanks, Remove wind walls from mud tanks with crane. Move cement silo & water tank. Move all three vendor shacks. Check end play
on Top Drive, Install shipping beams in cellar. R/D Bails, Saver sub & remove mud hose & service loop lines. Remove Top Drive Torque Bushing and cradle
Top Drive. Lower Top drive to Catwalk. Hook up bridle lines, Prep derrick to be scoped down. Removed T-bar and turn buckles on torque tube. Scope derrick
down laying lower torque tube on catwalk. Remove lower torque tube section and set on catwalk. Hang off blocks and pin upper wind walls in derrick layover
position. Remove centrifuge from pits and stage in cuttings box. Transfer fuel from rig tank for move. Unspool drilling line and cut off 24'. Hang off drill line,
service loop and kelly hose in derrick. Fold up derrick board and perform derrick inspection. Lay over derrick and unpin mast cylinders from derrick and dress
derrick out for rig move. R/D boilers and both mud pumps. Lower Degasser and Pit roofs 1, 2 and 3. R/D water and air lines. Start unplugging electrical from
gens to pits. Rig was released at 06:00 hrs.
R/U testing equipment to perform MIT on Tbg. & IA. Purge all lines of air. Pump 1.9 BBLs into Tbg for a pressure of 3650psi. Hold for 30 charted minutes. Good
test and
pump 30pppgpppgppp
BBLs 10.5ppg Spacer followed by 120 BBLs of. 12ppg Lead cement followed by 22 BBLs of 15.3ppg Tail cement. Close TIW on cement head and wash cementppg p y ppg y ppg
across top of cement head with water to cuttings tank. Close block valve to cuttings tank open TIW on cement head drop drill pipe wiper plug and. pump 10pggppppppg pp
BBLs water followed with 9.1ppg mud from rig pumped by HES total displacement pumped was 95.5 BBLs with no indication of bump.Pumped another 4.5 BBlsppg g p p y p p p
(100 BBLs Total) with no bump and went to secondary release of Liner Top Packer. No indication of hanger. setting.
pp
Cont. RIH with 4 1/2" liner
Activity Date Ops Summary
7/7/2023 PTSM/SIMOPS,Mobe eq. from Barge landing to location on C pad,Spot Eq.for well work, mobe crane to location. R/U Coil eq. run circ lines, start filling supply
tank w/water. N/U BOPE, run choke, kill lines & choke manifold. Fill surface Eq, Shell test BOPE 250/3500 repair leaks till good. Test BOPE as per Hilcorp &
AOGCC requirements, Witness was waived by AOGCC inspector Jim Regg @17:57 on 7-5-23, tested 250/3500 Had one FP on CMV #3 , Serviced & re-tested
good. R/U fluid pump & circulating lines, Finish filling supply tank with water. Secure well, SDFN.
7/8/2023 PTSM, SIMOPS,,Fire eq. P/U injector, M/U coil connector, pull test t/25k, good, M/U BHA- DF check valve, jars, disconnect, circ sub, 2.88 mud motor, but sb,
3.75" rock bit. P/T t/3500psi good, surface test mud motor, good. Stab on to well, P/T break 250/3500, good,,RIH @ 120FPM, t/6000', up wt 22k, dn wt 9k,Cont.
in hole tag @6433'ctm, reciprocate pipe, pump 1.75BPM 3000psi, add friction reducer, POOH pumping @ 2BPM, 2400psi, displacing well t/drill water, clean
returns after 90 bbls pumped cont. Pump OOH total of 147bbls pumped. bump up, secure well. Break injector off, l/d BHA, park injector. R/U AK e-line, P/U CBL
tool string, stab lub onto well, P/T repairing leaks as needed till good test t/2500psi. RIH w/logging tools, calibrate same, make pass down t/6421' ELM, repeat
pass up logging t/ 2400', send logs to town for correlation & interpretation, cont. POOH. Shut in well, L/D e-line tools, install night cap, SDFN.
7/9/2023 PTSM, SIMOPS meeting. Break down CBL logging tools Prep for Halliburton PNL tools,Mobe Halliburton TOOLS & hands to Beluga,,Had issue integrating
Halliburton Warrior panel to AK e-line eq. Service e-line unit & prep tools while mobing xo for Warrior panel to Beluga. P/U Halliburton, PNL logging tools, stab
lubricator, PT 250/2500 good,RIH w/tools to 6100',Log up @ 12FPM t/2000',POOH let tools cool @ 200', cont POOH, secure well, break off lubricator & L/D,
install night cap, SDFN.
7/10/2023 PTSM,SIMOPS,R/U Haliburton CBL tools to hoist on AK e-line, stab Lubricator, PT t/2500 good,RIH T/tag, p/u log OOH t/2000', send logs in, verify same results
from AK -e-line logs. Rig down secure well. Work plan foward with town engineers, start mobing eq.& supplies for CMT job.
7/11/2023 PTSM,SIMOPS,,M/U check valve & nozzle to coil, stab injector to wellhead, P/T same t/3500psi good,RIH tag @ 6432' CTM,,Circulate well @ 2BPM, swap over
to 3% KCL,,Pressure up casing t/3000psi good,POOH R/D injector. M/U E-line tool string with 2" gun, 0 deg Phasing w/12 shots, 4', stab lubricator Test
t/2500psi good,RIH correlate & place hole punch @ 6040-6044', Pressure up well t/500psi, Fire punch, good indication fired, lost 150 psi, POOH R/D lubricator
install night cap. Pump down kill line checking injection, stage up slow, pump .75 BPM, pressure broke over @ 1520psi, cont. pump staging up t/1.5 BPM,
1450psi FCP, pumped 30 bbls total. Secure well.
7/12/2023 PJSM, SIMOPS,P/U injector & lubricator, M/U test sub, pull test t/25k good, PT coil t/3500 good, P/U BHA- disconnect, xo, retainer running tool w/retainer =
9.83',RIH t/6100', up wt 22k, dn wt 9k, Drop 5/8" setting ball, pickup placing retainer @6000', circulate ball & check coil pump pressures with 3% kcl Brine, .75
BPM-770psi, 1 BPM -1000psi, 1.25 BPM- 1275, finish circulating ball to seat @ .4bpm, ball landed pressure up t/2k psi pressure dropped off setting retainer, set
down 6k verify set. Pressure up annulus t/500psi shut in to monitor during job. check injection rates with Brine, pump @.75 BPM 2100psi - 770 coil
friction=1330psi, @1 BPM 2400psi - 1000 psi coil friction =1400psi, inject 25 bbls 3% kcl. Spot & Rig up Cementers, mix make up water. PJSM, cementers fill
lines, P/T to 4k psi, good,,Start batching up 15.8 ppg cmt, pump cmt filling coil @ .75 bpm, pump pressure 3700 psi - 1330psi injection pressure with cmt at end
of coil, cont. pump 71 bbls 15.8ppg cmt displace coil with 30 bbls water, max/FCP injection pressure 2210psi. CMT in place 16:40,Unsting from retainer
pressure drop on coil verifying out, annulus pressure @ 350, open bleeder bled down and monitor, no flow, Rev circ two coil volumes cleen @ 1.25bpm 1050psi
while POOH,Bump up, secure well, break off injector, L/D BHA, stand back injector, install night cap. WOC.
7/14/2023 PTSM,SIMOPS,,R/U AK e-line, m/u CBL tools, M/U lubricator, PT t/2500 good,RIH calibrate tools, cont. RIH t/tag retainer, 5996', log up t/2200', cont POOH,
secure well, l/d lubricator & tools, send logs to town. R/U PT casing t/3000psi good. P/U coil injector, m/u rev nozzle, stab onto well, PT t/3500psi good,RIH t/
2493',Attempt to pump N2, unable to prime pump, trouble shoot & repair same. Start blowing down well, while running in hole t/tag retainer @~6000', p/u 2', up
wt 21k, dn wt 8k,,Cont. Blowing well dry n2, fluid stalled out had 1880 psi, POOH t/5100' fluid unloading, RIH t/retainer cont. pumping n2, recovered 121bbls
fluid,Cont. pumping & POOH lost prime on n2 pump @ ~1300', cont POOH bump up. shut in well,Breakoff injector, l/d lubricator & down stack injector, install
night cap. Unable to catch prime in n2 pump, will try again in AM.
n (LAT/LONG):
evation (RKB):
API #:
Well Name:
Field:
County/State:
BRU 223-34
Beluga River
Hilcorp Energy Company Composite Report
, Alaska
Contractor
AFE #:
AFE $:
Job Name:231-00084 BRU 223-34 Completion
Spud Date:
7/15/2023 PTSM, SIMOPS,,Fox coil, fire up eq. pre cool n2 pump, start pump no issues, open well 680psi, cont pump & build t/1780psi,Shut in well, R/D pump lines, r/d
rest of coil eq. & move to edge of pad,,R/U e-line, arm guns 1 & 2, on switches (5' each ) #1 ccl to TS=15.8', #2 CCL TO ts 8.6', 2 3/4" GUNS, 6 SPF, 60 DEG
phasing, stab onto well, PT t/2500 good,RIH t/5900' run correlation pass up t/ 4600', send logs to town verify log on depth. good. RIH, pull first gun into place,
CCL 5832.2', top shot 15.8' from ccl placing shots 5848-5853, wellhead pressure 1800psi, fire shots, good indication shots fired, no pressure change, inital
1800, 5 min 1800, 10 min 1800, 15 min 1800,,Pull into position for second gun- CCL-5815.4', top shot 8.6' from CCL, placing shots 5824-5829', wellhead
pressure 1800psi, fire shots good indication shots fired, slight bobble on pressure gauge 1805, no change on next 5/10/15 min monitoring. POOH all shots fired,
small amount of gun debris in bullnose slight damp no water, wellhead pressure back at 1800psi,M/U guns 3&4 with switch, top shot gun #3 19' from CCL, gun
#4 top shot 9.6' from CCL,RIH, pull log correlate, pull gun #3 into place, CCL 5785', top shot 19' from ccl placing shots 5804-5814, wellhead pressure 1800psi,
fire shots, good indication shots fired, no pressure change, inital 1800, 5/10/15 min 1800,,Pull into position for gun #4- CCL-5735.4', top shot 9.6' from CCL,
placing shots 5745-5753', wellhead pressure 1800psi, fire shots good indication shots fired, 1800, no change on next 5/10/15 min monitoring. POOH all shots
fired, bullnose dry gun debris,M/U guns 5 & 6 with switch, top shot gun #5 15.2' from CCL, gun #6 top shot 7.8' from CCL,RIH, pull log correlate, pull gun #5 into
place, CCL 55714.8', top shot 15.2' from ccl placing shots 5730-5740, wellhead pressure 1790psi, fire shots, good indication shots fired, no pressure change,
initial 1790, 5/10/15 min 1790,,RIH, pull log, correlate, pull gun #5 into place, CCL 5714.8', top shot 15.2' from ccl placing shots 5730-5740', wellhead pressure
1790psi, fire shots, good indication shots fired, no pressure change, initial 1790, 5/10/15 min 1790,,Pull into position for gun #6- CCL-5683.2', top shot 7.8' from
CCL, placing shots 5691-5697', wellhead pressure 1790psi, fire shots good indication shots fired, 1790, no change on next 5/10/15 min monitoring. POOH all
shots fired, bull nose dry with debris. M/U guns 7 & 8 with switch, top shot gun #7 19' from CCL, gun #8 top shot 9.6' from CCL,RIH, pull log correlate, pull gun
#7 into place, CCL 5663', top shot 19' from ccl placing shots 5682-5688, wellhead pressure 1790psi, fire shots, good indication shots fired, no pressure change,
initial 1790, 5/10/15 min 1790,,Pull into position for gun #8- CCL-5659.4', top shot 9.6' from CCL, placing shots 5669-5677', wellhead pressure 1790psi, fire
shots good indication shots fired, 1790,no change on next 5/10/15 min monitoring. POOH all shots fired slight change in wellbore pressure while POOH,
1780,,R/D for night, install night cap, well bore pressure 1770 end of day.
7/16/2023 PTSM, SIMOPS,Check well pressure, 1810psi, M/U gun #9, top shot 8.9' from CCL stab lub, PT good. RIH, pull log correlate, pull gun #9 into place, CCL
5565.1', top shot 8.9' from ccl placing shots in H9 5574-5599', wellhead pressure 1810psi, fire shots, good indication shots fired, no pressure change, initial
1810, 5/10/15 min. POOH all shots fired Dry,Re-head line, test good, M/U gun #10, top shot 8.9' from CCL,RIH, pull log correlate, pull gun #10 into place, CCL
5541.1', top shot 8.9' from ccl placing shots in H1 5550-5564', wellhead pressure 1810psi, fire shots, good indication shots fired, no pressure change, initial
1810, 5/10/15 min. POOH all shots fired, Dry. bull plug. M/U gun #11, top shot 16.7' from CCL,RIH, pull log correlate, pull gun #11 into place, CCL 5520.3', top
shot 16.7' from ccl placing shots in H1 5537-5542', wellhead pressure 1800psi, fire shots, good indication shots fired, no pressure change, initial 1800, 5 min
1795 10 min 1795, 15 min 1780 psi. POOH all shots fired, Dry. bull plug. M/U gun #12, top shot 11' from CCL, RIH, pull log correlate, pull gun #12 into place,
CCL 5307', top shot 11' from ccl placing shots in G6 5318-5336', wellhead pressure 1770psi, fire shots, good indication shots fired, no inital pressure change,
initial 1770, 5 min 1770, 10 min 1770, 15 min 1760 psi. POOH all shots fired, Dry. bull plug. M/U gun #13, top shot 16.7' from CCL, Wellhead 1740psi,RIH, pull
log correlate, pull gun #13 into place, CCL 5206.1', top shot 12.9' from ccl placing shots in G5 5219-5235', wellhead pressure 1740psi, fire shots, good indication
shots fired, initial pressure change, initial 1750, 5 min 1740, 10 min 1740, 15 min 1735 psi. POOH all shots fired, Dry. bull plug. M/U gun #14, top shot 8.9' from
CCL, Wellhead 1720psi. RIH, pull log correlate, pull gun #14 into place, CCL 5161.1', top shot 8.9' from ccl placing shots in G3 5170-5184', wellhead pressure
1700psi, fire shots, good indication shots fired, no initial pressure change, in 5 min 1600, 10 min 1500, 15 min 1425, POOH all shots fired, Dry bull plug,in 50
additional min down to 1150psi. Rigged e-line down, secured well.
7/20/2023 Short fog delay then AK E-Line flew from Kenai Airport to Beluga River office. Check in. PJSM and permit. Source triplex, bleed tank and man lift. Mobe E-line
equipment from D pad to C pad. MIRU AK E-Line,,P Test 250 / 2500 PSI. Test good. RIH w/ Gun ONE. Gun is 2-3/4" x 12' long. To shoot Beluga F10 zone
5059' to 5071'. CCL to TS = 10.8' / CCL depth will be 5048.2' to place TS at 5059'. Correlation log Gun ONE. Log sent to town for approval. Town approved
whole log strip for remaining shots. Spot and fire Gun ONE. POOH. Start PSI - 661 / 5 Min - 681 / 10 Min - 677 / 15 Min - 699 / 20 Min - 824 / 25 Min - 845. OOH.
Lay down Gun ONE. All shots fired. Small amount muddy sand in end cap. P/U Gun TWO. RIH w/ Gun TWO. Gun is 2-3/4" x 14' long. To shoot Beluga F7 zone
4971' to 4985'. CCL to TS = 9' / CCL depth will be 4962' to place TS at 4971'. Tie in log. Spot Gun TWO. Fired gun. POOH. Start PSI - 711 / 5 Min - 714 / 10 Min
- 707 / 15 Min - 852 / 20 Min - 874. OOH. Lay down Gun TWO. End camp was damp but not full water. All shots fired. P/U Gun THREE. RIH w/ Gun THREE.
Gun is 2-3/4" x 14' long. To shoot Beluga F7 zone 4944' to 4958'. CCL to TS = 9' / CCL depth will be 4935' to place TS at 4944'. Tie in log. Spot Gun THREE.
Fired gun. POOH. Start PSI - 779 / 5 Min - 790 / 10 Min - 797 / 15 Min - 850 / 20 Min - 888. OOH. Lay down Gun THREE. End camp was damp but not full water.
All shots fired. Lay down lubricator. Nite cap well. Secure equipment. SDFN. Plan forward: Make last 2 perf gun runs in morning for F7 zones.
7/21/2023 Morning meeting. PJSM and permit. Travel to C pad. AK E-Line rig back on well. RIH w/ Gun FOUR. Gun is 2-3/4" x 6' long. To shoot Beluga F7 zone 4871' to
4877'. CCL to TS = 9' / CCL depth will be 4862' to place TS at 4871'. Tie in and spot Gun FOUR. Fire gun. POOH. Start PSI: 691 / 5 Min - 695 / 10 Min - 705 /
15 Min - 847 / 20 Min - 851. OOH. Lay down Gun FOUR. All shots fired. P/U Gun FIVE. RIH w/ Gun FIVE. Gun is 2-3/4" x 12' long. To shoot Beluga F7 zone
4844' to 4856'. CCL to TS = 10.8' / CCL depth will be 4833.2' to place TS at 4844'. Tie in and spot Gun FIVE. Fire gun. POOH. Start PSI: 776 / 5 Min - 774 / 10
Min - 772 / 15 Min - 765. OOH. Lay down Gun FIVE. All shots fired. RDMO AK E-Line. Move equipment to D pad for storage. Otter down for mechanical. Stand
by for travel. Return to AK E-Line shop.
TD Shoe Depth: PBTD:
Jts.
2
67
Yes X No X Yes No 10
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes X No
Liner hanger test pressure:Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Casing (Or Liner) Detail
Shoe 8 5/8
Rotate Csg Recip Csg Ft. Min. PPG9
Shoe @ 2853.87 FC @ Top of Liner2,766.78
Floats Held
Spud Mud
CASING RECORD
County State Alaska Supv.R Pederson / J Riley
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 223-34 Date Run 6-Jun-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC Innovex 1.48 2,853.87 2,852.39
Csg Wt. On Hook:75,000 Type Float Collar:Innovex No. Hrs to Run:7
95
99
620
FI
R
S
T
S
T
A
G
E
10.5Tuned 60
122/127
1455
40
HES
15.8 35
Bump press
Visual
Bump Plug?
21:40 6/6/2023 Surface
2,854.002,863.00 2,767.00
CEMENTING REPORT
Csg Wt. On Slips:
Spud Mud
12 169
Type of Shoe:Innovex Bullnose Casing Crew:Parker
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
3 bow springs on shoe track, 1 bow spring on every 4th joint up to 433'
Casing 7 5/8 29.7 L-80 CDC USS 84.33 2,852.39 2,768.06
Float Collar 8 5/8 BTC Innovex 1.28 2,768.06 2,766.78
Casing 7 5/8 29.7 L-80 CDC USS 2,744.53 2,766.78 22.25
Casing Hanger 16 CDC Cactus 1.30 22.25 20.95
Type I II 392 2.44
Type I II 173 1.16
4.5
TD Shoe Depth: PBTD:
Jts.
1
1
121
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?:X Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp: Yes X No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface? Yes X No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Type 1/2 361 2.39
1/2 98 1.24
4
2,621.99 2,600.25
3.95 2,625.94 2,621.99
SLZXP 7 5/8 JFE Lion Baker 21.74
Pup Joint 4 1/2 12.6 L-80 JFE Lion JFE
6,426.81
4.5" Joints 4 1/2 12.6 L-80 JFE Lion JFE 3,800.87 6,426.81 2,625.94
6,458.94 6,427.84
Landing Collar Jhobbs 1.03 6,427.84
1.34 6,460.28 6,458.94
4.5" Joint 4 1/2 12.6 L-80 JFE Lion JFE 31.10
Float Collar Frontier
1 centralizer on every other joint for the first 111 jts
Joint 4 1/2 12.6 L-80 JFE Lion JFE 31.15 6,491.43 6,460.28
SLZXP
www.wellez.net WellEz Information Management LLC ver_04818br
3
Type of Shoe:Summit Guide Casing Crew:Parker
12 120
6,493.006,500.00
CEMENTING REPORT
Csg Wt. On Slips:
KCL/Polymer
8:15 6/22/2023 2,875'
15.3 20
Bump press
CBL 7-14-23 run post squeeze job
Bump Plug?
90/90
0
Haliburton
FI
R
S
T
S
T
A
G
E
10.5 30
9.2 4
1104
Csg Wt. On Hook:110,000 Type Float Collar:Frontier Oil Tools No. Hrs to Run:16
Summit 1.57 6,493.00 6,491.43
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.BRU 223-34 Date Run 22-Jun-23
CASING RECORD
County State Alaska Supv.J Murphy / C Yearout
6,460.28
Floats Held
KCL/Polymer
Rotate Csg Recip Csg Ft. Min. PPG9.15
Shoe @ 6493 FC @ Top of Liner 2600
Casing (Or Liner) Detail
Float Shoe
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AE A
A
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.06.26 10:03:38 -08'00'Chelsea Wright Digitally signed by Chelsea Wright
Date: 2023.06.26 10:54:45 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 07/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230728
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU-23 50133206350000 214093 7/16/2023 HALLIBURTON PPROF
BCU-24 50133206390000 214112 7/15/2022 HALLIBURTON PPROF
BRU 223-34 50283201880000 223041 7/9/2023 HALLIBURTON RMT3D
KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON EPX
KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON MFC
KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON EPX
KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON MFC
KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON EPX
KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON MFC
MPU B-24 50029226420000 196009 7/24/2023 HALLIBURTON WFL-TMD3D
MPU B-34 50029235690000 216139 7/23/2023 HALLIBURTON WFL-TMD3D
MPU B-50 50029232400000 204252 7/21/2023 HALLIBURTON WFL-TMD3D
MPU E-23 50029225700000 195094 6/17/2023 HALLIBURTON COILFLAG
MPU F-17 50029228230000 197196 7/2/2023 HALLIBURTON COILFLAG
MPU L-13A 50029223350100 223017 6/21/2023 HALLIBURTON COILFLAG
MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON COILFLAG
MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON RBT
PBU 11-07 50029206870000 181177 6/28/2023 HALLIBURTON RMT3D
SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON EPX
SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON MFC
SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON EPX
SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON MFC
Please include current contact information if different from above.
T37886
T37887
T37888
T37889
T37889
T37890
T37890
T37891
T37891
T37892
T37893
T37894
T37895
T37896
T37897
T37898
T37898
T37899
T37900
T37900
T37901
T37901
BRU 223-34 50283201880000 223041 7/9/2023 HALLIBURTON RMT3D
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.01
10:05:02 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 07/25/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230725
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BRU 222-34 50283201860000 222039 6/29/2023 AK E-LINE Perf-ProductionProfile
BRU 223-34 50283201880000 223041 7/14/2023 AK E-LINE CBL/Perf
BRU 223-34 50283201880000 223041 7/16/2023 AK E-LINE Perf
BRU 244-27 50283201850000 222038 6/30/2023 AK E-LINE Perf
END 1-01 50029218010000 188037 7/9/2023 AK E-LINE Plug/Cement
END DIU 1-01 50029218010000 188037 7/7/2023 AK E-LINE Cross-Flow-Detect
GO 8 50133206510000 215077 7/13/2023 AK E-LINE Perf
KBU 33-06X 50133205290000 203183 7/18/2023 AK E-LINE GPT/Patch
PBU F-29B 50029216270200 211147 7/8/2023 AK E-LINE CIBP
Please include current contact information if different from above.
T37872
T37873
T37873
T37874
T37875
T37875
T37876
T37877
T37878
BRU 223-34 50283201880000 223041 7/14/2023 AK E-LINE CBL/Perf
BRU 223-34 50283201880000 223041 7/16/2023 AK E-LINE Perf
Kayla Junke
Digitally signed by Kayla
Junke
Date: 2023.07.25
12:04:00 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 7/21/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resources Technician
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 223-34
- PTD 223-041
- API 50-283-20188-00-00
FINAL LWD FORMATION EVALUATION LOGS (06/03/2023 to 06/20/2023)
EWR-M5, AGR, PCG, ADR, ALD, CTN, ROP (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Folder Contents:
Please include current contact information if different from above.
PTD: 223-041
T37871
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.07.24
09:47:24 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal
Received By: Date:
DATE: 07/21/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
BRU 223-34
- PTD 223-041
- API 50-283-20188-00-00
MUDLOGS - EOW DRILLING REPORTS (06/03/2023 to 06/20/2023)
1. FINAL EOW REPORT
2. DAILY REPORTS
3. SHOW REPORTS
4. DIGITAL DATA (LAS)
5. MUDLOG PRINTS (2” and 5” MD and TVD COLOR PRINTS – TIFF AND PDF FORMATS)
Formation Log
LWD Combo Log
Gas Ratio Log
Drilling Dynamics Log
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-34
T37871
Kayla
Junke
Digitally signed by Kayla Junke
Date: 2023.07.24 09:51:56 -08'00'
1
Regg, James B (OGC)
From:Jay Murphy - (C) <Jay.Murphy@hilcorp.com>
Sent:Saturday, June 24, 2023 12:17 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Subject:MIT Hilcorp 147 06-24-2023
Attachments:MIT Hilcorp 147 06-24-2023.xlsx
Thank You and Best Regards,
Jay Murphy/ DSM
Hilcorp Alaska, LLC
HAK Rig 147
Office: 907‐776‐6776
Cell: 907‐715‐9211
Jay.Murphy@Hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
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.
Beluga River Unit 223-34PTD 2230410
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230410 Type Inj N Tubing 0 3650 3650 3650 Type Test P
Packer TVD 2390 BBL Pump 1.9 IA 0 0 0 0 Interval O
Test psi 3500 BBL Return 1.7 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230410 Type Inj N Tubing 0 290 290 290 Type Test P
Packer TVD 2390 BBL Pump 1.4 IA 0 3700 3700 3700 Interval O
Test psi 3500 BBL Return 1.3 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp Alaska LLC
Beluga River Unit/ 223-34/ C Pad
Jay Murphy
06/24/23
Notes:Post completion MIT-T per PTD. AOGCC witness waived
Notes:
Notes:
Notes:
BRU 223-34
BRU 223-34
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Post completion MIT-IA per PTD. AOGCC witness waived
Notes:
Notes:
Form 10-426 (Revised 01/2017)2023-0624_MITP_BRU_223-34_2tests
1-Gas producer
1-Gas producer
J. Regg; 8/24/2023
1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2
2. Operator Name:4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
6,500 N/A
Casing Collapse
Structural
Conductor 1,410psi
Surface 4,790psi
Intermediate
Production 7,500psi
Liner
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations:OIL WINJ WDSPL Suspended
16. Verbal Approval:Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
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
FEDA029656 / FEDA029657
223-041
50-283-20188-00-00
Hilcorp Alaska, LLC
Proposed Pools:
12.6# / L-80
TVD Burst
~2,605'
8,430psi
2,590'
Size
120'
2,853'
MD
See Attached Schematic
2,980psi
6,880psi
120'120'
2,853'
July 6, 2023
Tieback 4-1/2"
6,498'
Perforation Depth MD (ft):
3800 Centerpoint Drive, Suite 1400
Anchorage, Alaska 99503
Beluga River Unit (BRU) 223-34CO 802
Same
6,106'4-1/2"
~2006psi
3,893'
N/A
Length
Liner Top Pkr; N/A 2,605' MD/2,378' TVD; N/A
6,107 6,431 5,752
Beluga River Sterling-Beluga Gas
16"
7-5/8"
See Attached Schematic
m
n
P
s
66
t
2
N
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:01 pm, Jun 23, 2023
323-360
Digitally signed by Noel
Nocas (4361)
DN: cn=Noel Nocas (4361)
Date: 2023.06.23 14:38:44 -
08'00'
Noel Nocas
(4361)
DSR-6/23/23BJM 6/26/23
Submit CBL to AOGCC and obtain approval before perforating.
X
10-407
CT BOP test to 3500 psi
MDG 6/27/2023
JLC 6/27/2023
06/27/23
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.06.27
20:51:57 -05'00'
RBDMS JSB 062823
Well Prognosis
Well Name:BRU 223-34 API Number:50-283-20188-00-00
Current Status:Gas Producer Permit to Drill Number:223-041
First Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C)
Second Call Engineer:Chad Helgeson (907) 777-8405 (O)
Maximum Expected BHP: 2596 psi @ 5900’ TVD (Based on 0.44 psi/ft gradient))
Max. Potential Surface Pressure: 2006 psi (Based on 0.1 psi/ft gas gradient to surface)
Well Status: New Drill Initial Completion
Brief Well Summary:
BRU 223-34 is a grass roots well targeting the Sterling and Beluga sands in the Beluga River Unit. The objective
of this sundry is to clean out the liner with coil tubing/nitrogen and perforate multiple Beluga sands. All sands
lie in the Sterling Beluga Gas Pool.
Wellbore Conditions:
Drilling will leave the cemented 4.5” liner full of drilling mud, with the 4.5” tubing and annulus displaced to KCL.
Procedure:
1. Review all approved COAs
2. Provide AOGCC 48hrs notice for BOP test
3. MIRU Coiled Tubing, PT BOPE to 3500 psi. higher test pressure to accommodate reverse out
4. Clean out wellbore to TD, displace to water
5. Log CBL, submit results to AOGCC
a. Log CBL on coil with memory toolstring OR
b. RU E-line over coil, PT lubricator to 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 below interval from the bottom up:
Sand MD TVD
Top Sand Beluga D 3913 3579’ estimated depths
Bottom Sand Beluga I 6275 5900’ estimated depths
a.Final depths to be picked after cased hole neutron log is run due to lack of open hole data
b. If any zone produces sand and/or water or needs isolated, RIH and set plug above the
perforations OR patch across the perforations.
c. Frac Calcs: Using 13.8 ppg EMW FIT at the surface casing shoe (0.717 psi/ft frac grad)
d. Shallowest Allowable Perf TVD = MPSP/(0.717-0.1) = 2006 psi / 0.617 = 3251‘ TVD
10. RDMO
11. Turn well over to production & flow test well
t Beluga sands w
= estimated top of Sterling B
from PTD formation list. MDG
Well Prognosis
Attachments:
1. As-built Well Schematic
2. Proposed Well Schematic
3. Coil Tubing BOP Diagram
4. Standard Nitrogen Operations
5. AOGCC RWO Change Form
Updated by DMA 06-22-23
CURRENT SCHEMATIC
Beluga River Unit
BRU 223-34
PTD: 50-283-20188-00-00
API: 223-34
PBTD = 6,431’ / TVD = 5,752’
TD = 6,500’ / TVD = 6,107’
RKB to GL = 20’
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 USS-CDC 6.875” Surf 2,853’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,605’ 6,498’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,605’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,605’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
2 ~1,500’ 3.958” 4.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface 40 bbls lead to surface
4-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
1
2
Updated by DMA 06-22-23
PROPOSED
Beluga River Unit
BRU 223-34
PTD: 50-283-20188-00-00
API: 223-34
PBTD = 6,431’ / TVD = 5,752’
TD = 6,500’ / TVD = 6,107’
RKB to GL = 20’
PERFORATION DETAIL
Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Bel D-I ±3,913' ±6,275’ ±3,579’ ±5,900’ 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 USS-CDC 6.875” Surf 2,853’
4-1/2" Prod Lnr 12.6 L-80 JFE LION 3.958” 2,605’ 6,498’
4-1/2" Prod Tieback 12.6 L-80 JFE LION 3.958” Surf 2,605’
16”
7-5/8”
9-7/8”
hole
4-1/2”
JEWELRY DETAIL
No. Depth ID OD Item
1 2,605’ 4.875” 6.540” Seal Stem / Liner hanger / LTP Assembly
2 ~1,500’ 3.958” 4.500” Chemical Injection Sub
OPEN HOLE / CEMENT DETAIL
7-5/8" TOC @ Surface 40 bbls lead to surface
4-1/2” Est. TOC @ TOL (40% excess)
6-3/4”
hole
1
2
Bel D-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.
Hilcorp Alaska, LLC
Hilcorp Alaska, LLC
Changes to Approved Rig Work Over Sundry Procedure
Subject: Changes to Approved Sundry Procedure for Well BRU 223-34 (PTD 223-041)
Sundry #: XXX-XXX
Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the
AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.
Sec Page Date Procedure Change New 403
Required?
Y / N
HAK
Prepared
By
(Initials)
HAK
Approved
By
(Initials)
AOGCC Written
Approval Received
(Person and Date)
Approval:
Asset Team Operations Manager Date
Prepared:
First Call Operations Engineer Date
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 223-34
JBR 07/27/2023
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:2
4-1/2" joint. Top rams shaft sealed failed. Blind rams cycled for a pass. Time reflects when I was on location testing.
Test Results
TEST DATA
Rig Rep:Davis/TrickOperator:Hilcorp Alaska, LLC Operator Rep:Pederson?Richardson
Rig Owner/Rig No.:Hilcorp 147 PTD#:2230410 DATE:6/8/2023
Type Operation:DRILL Annular:
250/2500Type Test:INIT
Valves:
250/5000
Rams:
250/5000
Test Pressures:Inspection No:bopSAM230611211530
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 9.5
MASP:
2401
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"x5"F
#2 Rams 1 Blinds FP
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 2-1/16"/3-1/8 P
Kill Line Valves 3 2-1/16"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1700
200 PSI Attained P27
Full Pressure Attained P89
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P4@2512
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P17
#1 Rams P5
#2 Rams P5
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9999
9
9
9
'LGQRWZLWQHVVUHWHVWRI8SSHU9%5
F
FP
Top rams shaft sealed failed.Blind rams
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________BELUGA RIV UNIT 223-34
JBR 07/26/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:
TEST DATA
Rig Rep:Brandon DavisOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson
Contractor/Rig No.:Hilcorp 147 PTD#:2230410 DATE:6/3/2023
Well Class:DEV Inspection No:divSAM230602201530
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:NA NA
Designed to Avoid Freeze-up?NA
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:9.875 P
Vent Line(s) Size:16 P
Vent Line(s) Length:143.5 P
Closest Ignition Source:93.6 P
Outlet from Rig Substructure:129.5 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:30 P
Knife Valve Open Time:28 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1550
200 psi Recharge Time:P38
Full Recharge Time:P116
Nitrogen Bottles (Number of):P4
Avg. Pressure:P2500
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
NA NAMud System Misc:
Knife Valve (open) and Annular (close)
times slow by compliant -- jbr
Attachments - Pad drawing; Diverter vent line orientation; Gas Alarm test report
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 Myers
Drilling Manager
Hilcorp Alaska LLC
3800 Centerpoint Dr, Suite 1400
Anchorage, AK, 99503
Re: Beluga River, Sterling-Beluga Gas, BRU 223-34
Hilcorp Alaska, LLC
Permit to Drill Number: 223-041
Surface Location: 270’ FNL, 378’ FEL, Sec 4, T12N, R10W, SM, AK
Bottomhole Location: 1840' FSL, 2395' FEL, Sec 34, T13N, R10W, SM, AK
Dear Mr. Meyers:
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 June, 2023.
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.06.01 08:16:05
-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: 7,400' TVD: 6,990'
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): 103.2 15. Distance to Nearest Well Open
Surface: x-315276 y- 2619657 Zone-4 84.7 to Same Pool:1183' to BRU 243-34
16. Deviated wells:Kickoff depth: 250 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 31.2 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 USS-CDC 2,830' Surface Surface 2,830' 2,563'
6-3/4" 4-1/2" 12.6# L-80 JFE LION 4,770' 2,630' 2,392' 7,400' 6,990'
Tieback 4-1/2" 12.6# L-80 JDE LION 2,630' Surface Surface 2,630' 2,392'
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
6/6/2023
4066' to nearest unit boundary
Frank Roach
frank.roach@hilcorp.com
907-777-8413
Tieback Assy.
Drilling Manager
Monty Myers
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):Perforation Depth MD (ft):
Production
Liner
Intermediate
Conductor/Structural
Authorized Title:
Authorized Signature:
Authorized Name:
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Driven
L - 940 ft3 / T - 209 ft3
Effect. Depth MD (ft):Effect. Depth TVD (ft):
2861
18. Casing Program:Top - Setting Depth - BottomSpecifications
3100
GL / BF Elevation above MSL (ft):
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 - 846 ft3 / T - 104 ft3
2401
758' FSL, 2533' FEL, Sec 34, T13N, R10W, SM, AK
1840' FSL, 2395' FEL, Sec 34, T13N, R10W, SM, AK
N/A
3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503
Hilcorp Alaska, LLC
270’ FNL, 378’ FEL, Sec 4, T12N, R10W, SM, AK A029656 / A029657
BRU 223-34
Beluga River Unit
Sterling - Beluga Gas Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
s
D
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
4.25.2023
By Kayla Junke at 9:06 am, Apr 26, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.04.25 15:21:35 -08'00'
Monty M
Myers
50-283-20188-00-00
BJM 5/30/23
Submit FIT/LOT data to AOGCC within 48 hrs of test.
223-041
BOP test frequency is once per 7 days.
SFD 5/28/2023
Initial BOP test to Rated Working Pressure, Initial annular test to 2500 psi.
Subsequent BOP tests to 3500 psi, annular to 2500 psi.
DSR-4/26/23GCW 05/30/23
JLC 5/30/2023
06/01/23Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.06.01 08:16:31 -08'00'
BRU 223-34
Drilling Program
Beluga River Unit
Rev 0
April 20, 2023
BRU 223-34
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 4-1/2” Production Liner ...................................................................................................26
17.0 Cement 4-1/2” Production Liner .............................................................................................29
18.0 4-1/2” Liner Tieback Polish Run.............................................................................................32
19.0 4-1/2” Tieback Run, ND/NU, RDMO ......................................................................................33
20.0 Diverter Schematic ..................................................................................................................34
21.0 BOP Schematic ........................................................................................................................35
22.0 Wellhead Schematic.................................................................................................................36
23.0 Days Vs Depth..........................................................................................................................37
24.0 Geo-Prog..................................................................................................................................38
25.0 Anticipated Drilling Hazards ..................................................................................................39
26.0 Hilcorp Rig 147 Layout ...........................................................................................................41
27.0 FIT/LOT Procedure.................................................................................................................42
28.0 Choke Manifold Schematic......................................................................................................43
29.0 Casing Design Information......................................................................................................44
30.0 6-3/4” Hole Section MASP .......................................................................................................45
31.0 Spider Plot w/ 660’ Radius for SSSV.......................................................................................46
32.0 Surface Plat (As-Staked NAD27 & NAD83)...........................................................................47
Page 2 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
1.0 Well Summary
Well BRU 223-34
Pad & Old Well Designation BRU C Pad –Grassroots Well
Planned Completion Type 4-1/2”Production Liner w/Tieback (monobore)
Target Reservoir(s)Sterling/Beluga
Planned Well TD, MD / TVD 7,400 MD / 6,990’ TVD
PBTD, MD / TVD 7,320’ MD / 6,912’TVD
Surface Location (Governmental)270’ FNL, 378’ FEL, Sec 4, T12N, R10W, SM, AK
Surface Location (NAD 27)X=315276.20 Y=2619657.30
Surface Location (NAD 83)X=1455307.00 Y=2619411.00
Top of Productive Horizon
(Governmental)758' FSL, 2533' FEL, Sec 34, T13N, R10W, SM, AK
TPH Location (NAD 27)X=315331, Y=2620674
TPH Location (NAD 83)X=1455358 Y=2620434
BHL (Governmental)1840' FSL, 2395' FEL, Sec 34, T13N, R10W, SM, AK
BHL (NAD 27)X=315485, Y=2621753
BHL (NAD 83)X=1455512 Y=2621513
AFE Number
AFE Drilling Days 2 MOB, 21 DRLG
AFE Completion Days
AFE Drilling Amount
AFE Completion Amount
Maximum Anticipated Pressure
(Surface)2401 psi
Maximum Anticipated Pressure
(Downhole/Reservoir)3100 psi
Work String 4-1/2” 16.6# S-135 CDS-40
RKB –GL 103.2’(84.7 + 18.5)
Ground Elevation 84.7’
BOP Equipment 11” 5M Annular BOP
11” 5M Double Ram
11” 5M Single Ram
Page 3 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
2.0 Management of Change Information
Page 4 Version 0 April, 2023
BRU 223-34
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 CDC 6880 4790 683
Prod
6-3/4”4-1/2”3.958”3.833”5.002”12.6 L-80 JFE LION 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD (in)ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k
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).
Page 5 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on Wellez.
x Report covers operations from 6am to 6am
x 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. This helps later on when we pull end of well
reports.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a
username to login with.
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. John Coston: O: (907) 777-6726 C: (907) 227-3189
b. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753
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 mmyers@hilcorp.com, Frank.Roach@hilcorp.com, and
cdinger@hilcorp.com
5.6 Casing and Cmt report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
Frank.Roach@hilcorp.com, and cdinger@hilcorp.com
Page 6 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
6.0 Planned Wellbore Schematic
Page 7 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
7.0 Drilling / Completion Summary
BRU 223-34 is an S-shaped directional grassroots development well to be drilled from BRU C 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 ~31 deg. and TD of the well will be 7,400’ TMD/ 6,990’ TVD, ending with 12 deg inclination left in
the hole. Vertical section will be 2107 ft.
Drilling operations are expected to commence approximately June 1
st, 2023. The Hilcorp Rig # 147 will be
used to drill the wellbore then run casing and cement.
Surface casing will be run to 2,830 MD / 2,563’ 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 2,830’ 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 7,400’MD. Perform Wiper trip.
6. Make cleanout run
7. POOH laying down drill pipe.
8. Run and cmt 4-1/2”production liner.
9. PU clean out assembly and RIH to clean out 4-1/2”to landing collar
10. Displace well to 6% KCL completion fluid.
11. POOH and LD clean out assembly.
12. RIH and land 4-1/2” 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 + Pressures MWD w/e-line sonic log after TD
x e-line log dependent on hole conditions
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 (1) week intervals during the drilling of BRU 223-34. 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 250/5000 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 7 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.
initial test of BOP equipment will be to 250/5000 psi & subsequent tests of the BOP equipmentqp p q qp
will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initialp
and subsequent tests).
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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: 250/5000
(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 spud.
x 48 hours notice prior to testing BOPs.
x 48 hours notice prior to casing running & cement operations.
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 Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line
up with flowline later.
9.4 Ensure BRU 224-34 is shut in with all electrical components in the wellhouse de-energized and
Locked Out / Tagged Out.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Layout Herculite on pad to extend beyond footprint of rig.
9.7 R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher
offices.
9.8 RU Mud loggers on surface hole section for gas detection only. No samples required
9.9 After rig equipment has been spotted, R/U handi-berm containment system around footprint of
rig.
9.10 Mix mud for 9-7/8”hole section.
9.11 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 F 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. Hydraulics
calculations and recommended TFA is attached below.
x Workstring will be 4.5” 16.6# S-135 CDS40
11.2 4-1/2”Workstring & HWDP will come from Hilcorp.
11.3 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 9-7/8”hole section to 2,830’MD/ 2,563’ 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. Coal seam log will be
provided by Hilcorp Geo team.
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 2800’ 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
120-2830’ 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”CDC 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# CDC M/U torques
Casing OD Minimum Maximum Yield Torque
7-5/8”14,000 ft-lbs 17,000 ft-lbs 20,900 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% 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:
(2330’ –120’) x .03825 bpf x
1.75 =
147.93 830.6
Total LEAD:167.42 bbl 940.0 ft3
15.4 ppg TAIL:
9-7/8”OH x 7-5/8”Casing
annulus:
(2830’- 2330’)x .03825 bpf x
1.5 =
33.47 187.9
15.4 ppg TAIL:
7-5/8”Shoe track:
80 x .04592 bpf =3.67 20.6
Total TAIL:37.14 bbl 208.5 ft3
TOTAL CEMENT VOL:204.56 bbl 1148.5 ft3
Verified cement calcs. -bjm
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Cement Slurry Design:
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger
elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat
and continue with the cement job.
13.9 After pumping cement, drop top plug and displace cement with spud mud.
13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate.
13.11 Displacement calculation:
2830’-80’ = 2750’x .04592 bpf = 127 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 ½ 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 (2330’ MD to surface)Tail Slurry (2830’ to 2330’ 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
Frank.Roach@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 multi-bowl wellhead assy. Install 7-5/8” packoff P-seals. Test to 3000 psi.
14.3 N/U 11” x 5M BOP as follows:
x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M
mud cross/11” x 5M single ram
x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram
in btm cavity.
x Single ram should be dressed with 2-7/8” x 5” variable bore rams
x N/U bell nipple, install flowline.
x Install (2) manual valves & a check valve on kill side of mud cross.
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve.
14.4 Run 4-1/2”BOP test assy, land out test plug (if not installed previously).
x Test BOP to 250/5000 psi for 5/10 min. Test annular to 250/2500 psi for 10/10 min.
x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not
build up beneath the test plug.
14.5 R/D BOP test assy.
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 9.0 ppg 6% KCL PHPA mud system.
14.8 R/U mud loggers for production hole section.
14.9 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section.
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15.0 Drill 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. Hydraulics
calculations and recommended TFA is attached below.
15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill
the entire open hole section without having to pick up pipe from the pipeshed.
15.8 6-3/4” hole section mud program summary:
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
2,830’-7,400’9.0 –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 13.8 ppg EMW. Send the FIT results to the AOGCC within 48 hrs.
Note: Offset field test data predicts frac gradient at the 7-5/8”shoe to be between 11 - 15 ppg
EMW. A 13.8 ppg FIT results in a > 15 bbl kick tolerance volume while drilling with the
planned MW of 10.0 ppg and an assumed 0.5ppg kick intensity over anticipated pore pressure.
15.14 Drill 6-3/4” hole section to 7,400’ MD / 6,990’ 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 (3,913-4,521’ MD).
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’.
pp
7-5/8” burst is 6880 psi / 2 = 3440 psi.
Conduct FIT to 13.8 ppg EMW.
Agree -bjm
R/U and test casing to 3500 psi / 30 min.
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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 RU E-Line and perform wireline logging plan.
15.19 RD E-Line. PU 6-3/4” clean out BHA, and TIH to TD.
15.20 Pump sweep, CBU and condition mud for casing run.
15.21 POOH LDDP and BHA
15.22 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint.
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16.0 Run 4-1/2”Production Liner
16.1. R/U Weatherford 4-1/2”casing running equipment.
x Ensure 4-1/2”TXP BTC x CDS 40 crossover on rig floor and M/U to FOSV.
x R/U fill up line to fill casing while running.
x Ensure all casing has been drifted prior to running.
x Be sure to count the total # of joints before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.2. P/U shoe joint, visually verify no debris inside joint.
16.3. Continue M/U & thread locking shoe track assy consisting of:
x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked).
x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked).
x (1) Joint with Baker landing collar bucked on pin end & threadlocked.
x Solid body centralizers will be pre-installed on shoe joint an FC joint.
x Leave centralizers free floating so that they can slide up and down the joint.
x Ensure proper operation of float shoe and float collar.
x Utilize a collar clamp until weight is sufficient to keep slips set properly
16.4. Continue running 4-1/2”production liner
x Fill casing while running using fill up line on rig floor.
x Use “API Modified” thread compound. Dope pin end only w/ paint brush.
x Install solid body centralizers on every joint across zones of interest, TBD after LWD.
x Install solid body centralizers on every other joint to 7-5/8” shoe. Leave the centralizers free
floating.
16.5. Continue running 4-1/2” production liner
4-1/2” 12.6# JFELION M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”6,030 ft-lbs 6,690 ft-lbs 7,360 ft-lbs
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16.6. Run in hole w/ 4-1/2” 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 4-1/2” 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 4-1/2”Production Liner
17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume
gained during cement job. Ensure adequate cement displacement volume available as well.
Ensure mud & water can be delivered to the cmt unit at acceptable rates.
x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to
cuttings bin, prior to pumping any fluid downhole
x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur.
x Which pump will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Positions and expectations of personnel involved with the cmt operation.
x Document efficiency of all possible displacement pumps prior to cement job.
17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky
17.3. Pump 5 bbls spacer.
17.4. Test surface cmt lines to 4500 psi.
17.5. Pump remaining spacer.
17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed
weight. Job is designed to pump 40% OH excess.
Estimated Total Cement Volume:
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 4-1/2” liner
annulus:
200’ x .02624 bpf =5.25 29.5
12.0 ppg LEAD:
6-3/4” OH x 4-1/2” annulus:
(6900’ –2830’) x .02459 bpf x
1.4 =
140.11 786.7
Total LEAD:150.61 bbl 845.7 ft3
15.4 ppg TAIL:
6-3/4” OH x 4-1/2” annulus:
(7400’- 6900’) x .02459 bpf x
1.4 =
17.21 96.6
15.4 ppg TAIL:
4-1/2” Shoe track:
80 x .01522 bpf =1.22 6.8
Total TAIL:18.43 bbl 103.5 ft3
TOTAL CEMENT VOL:169.04 bbl 949.2 ft3
Verified cement calcs. -bjm
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Cement Slurry Design:
Lead Slurry (6900’ MD to 2630’ MD)Tail Slurry (7400’ to 6900’ 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 latching DP
dart into liner wiper plug. Note plug departure from liner hanger running tool and resume
pumping at full displacement rate. Displacement volume can be re-zeroed at this point.
17.9. If elevated displacement pressures are encountered, position casing at setting depth and cease
reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman
immediately of any changes.
17.10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger
(ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).
Hold pressure for 3-5 minutes.
17.11. Slack off total liner weight plus 30k to confirm hanger is set.
17.12. Do not overdisplace by more than ½ shoe track. Shoe track volume is 2 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 3000 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
Frank.Roach@hilcorp.com. This will be included with the EOW documentation that goes to the
AOGCC.
18.0 4-1/2”Liner Tieback Polish Run
18.1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe.
18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker
procedure.
18.3. POOH, and LDDP and polish mill.
x NOTE: If a cleanout run inside the 4-1/2” is needed, BOPs need to be tested with 2-7/8” test
joint to cover cleanout assembly.
18.4. If not completed, test 4-1/2” casing to 3,500 psi and chart for 30 minutes test 4-1/2” casing to 3,500 psi
Page 33 Version 0 April, 2023
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19.0 4-1/2” Tieback Run, ND/NU, RDMO
19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80 DWC/C-HT casing.
4-1/2” 12.6# JFELION M/U torques
Casing OD Minimum Optimum Maximum
4-1/2”6,030 ft-lbs 6,690 ft-lbs 7,360 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 4-1/2” liner and tieback to 3,500 psi and chart for 30 minutes. 48 hr notice required.
19.7 Test 7-5/8” x 4-1/2” 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
Test 7-5/8” x 4-1/2” annulus to 2,500 psi and
Page 34 Version 0 April, 2023
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20.0 Diverter Schematic
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Drilling Procedure
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21.0 BOP Schematic
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Drilling Procedure
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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Drilling Procedure
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24.0 Geo-Prog
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25.0 Anticipated Drilling Hazards
9-7/8”Hole Section:
Lost Circulation:
Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are
available on location to mix LCM pills at moderate product concentrations.
Hole Cleaning:
Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary.
Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
Maintain YP between 25 –45 to optimize hole cleaning and control ECD.
Wellbore stability:
Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with
intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger
than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity.
Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP
of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to
reduce the likelihood of washing out the conductor shoe.
To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30
prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be
found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be
achieved.
H2S:
H2S is not present in this hole section.
No abnormal pressures or temperatures are present in this hole section.
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BRU 223-34
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6-3/4” Hole Section:
Lost Circulation:
Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix
LCM pills at moderate product concentrations.
Given the volume of losses experienced in 241-34T in 2020 and BRU 244-27 and BRU 222-34 in 2022,
ensure all LCM inventory is fully stocked before drilling out surface casing.
Hole Cleaning:
Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary.
Optimize solids control equipment to maintain density and minimize sand content. Maintain YP
between 20 - 30 to optimize hole cleaning and control ECD.
Wellbore stability:
Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque
reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl
in system for shale inhibition.
Coal Drilling:
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The
need for good planning and drilling practices is also emphasized as a key component for success.
x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
x Use asphalt-type additives to further stabilize coal seams.
x Increase fluid density as required to control running coals.
x Emphasize good hole cleaning through hydraulics, ROP and system rheology.
H2S:
H2S is not present in this hole section.
No abnormal temperatures are present in this hole section.
Page 41Version 0April, 2023BRU 223-34Drilling ProcedureRev 026.0 Hilcorp Rig 147 Layout
Page 42 Version 0 April, 2023
BRU 223-34
Drilling Procedure
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27.0 FIT/LOT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Page 43Version 0April, 2023BRU 223-34Drilling ProcedureRev 028.0 Choke Manifold Schematic
Page 44 Version 0 April, 2023
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29.0 Casing Design Information
Page 45 Version 0 April, 2023
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Drilling Procedure
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30.0 6-3/4” Hole Section MASP
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Drilling Procedure
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31.0 Spider Plot w/ 660’ Radius for SSSV
Page 47 Version 0 April, 2023
BRU 223-34
Drilling Procedure
Rev 0
32.0 Surface Plat (As-Staked NAD27 & NAD83)
!"
#
-500
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
7000
7500True Vertical Depth (1000 usft/in)-500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500
Vertical Section at 5.00° (1000 usft/in)
BRU 223-34 wp09 tgt1
13 3/8" Casing
9 5/8" x 12 1/4"
4 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 0 0 0
3 5 0 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 4 0 0
BRU 223-34 wp09
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 3.5º/100' : 750' MD, 744.31'TVD
End Dir : 1397.72' MD, 1341.17' TVD
Start Dir 3º/100' : 2894.43' MD, 2617.73'TVD
End Dir : 3543.51' MD, 3217.77' TVD
Total Depth : 7400' MD, 6989.99' TVD
BRU_ST_A1_COAL
STERLING_B
STERLING_C
BELUGA_D
BELUGA_E
BELUGA_F
BELUGA_G
BELUGA_H
BELUGA_I
BRU_BELUGA_J
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 223-34
84.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2619657.30 315276.20 61° 9' 58.0856 N 151° 2' 46.1626 W
SURVEY PROGRAM
Date: 2023-04-24T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
18.50 2830.00 BRU 223-34 wp09 (BRU 223-34) 3_MWD+AX+Sag
2830.00 7400.00 BRU 223-34 wp09 (BRU 223-34) 3_MWD+AX+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
3039.20 2936.00 3358.77 BRU_ST_A1_COAL
3229.20 3126.00 3555.20 STERLING_B
3386.20 3283.00 3715.70 STERLING_C
3579.20 3476.00 3913.02 BELUGA_D
3801.20 3698.00 4139.98 BELUGA_E
4174.20 4071.00 4521.31 BELUGA_F
4722.20 4619.00 5081.55 BELUGA_G
5107.20 5004.00 5475.15 BELUGA_H
5864.20 5761.00 6249.06 BELUGA_I
6446.20 6343.00 6844.07 BRU_BELUGA_J
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 223-34, True North
Vertical (TVD) Reference:As-Staked RKB @ 103.20usft (HEC 147)
Measured Depth Reference:As-Staked RKB @ 103.20usft (HEC 147)
Calculation Method:Minimum Curvature
Project:Beluga River
Site:BRU C-Pad
Well:BRU 223-34
Wellbore:BRU 223-34
Design:BRU 223-34 wp09
CASING DETAILS
TVD TVDSS MD Size Name
110.00 6.80 110.00 13-3/8 13 3/8" Casing
2563.00 2459.80 2830.26 9-5/8 9 5/8" x 12 1/4"
6989.99 6886.79 7400.00 4-1/2 4 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
3 750.00 15.00 325.00 744.31 53.31 -37.33 3.00 325.00 49.85 Start Dir 3.5º/100' : 750' MD, 744.31'TVD
4 1397.72 31.47 7.96 1341.17 292.54 -62.33 3.50 67.37 286.00 End Dir : 1397.72' MD, 1341.17' TVD
5 2894.43 31.47 7.96 2617.73 1066.38 45.84 0.00 0.00 1066.31 Start Dir 3º/100' : 2894.43' MD, 2617.73'TVD
6 3543.51 12.00 7.00 3217.77 1303.43 77.83 3.00 -179.40 1305.26 End Dir : 3543.51' MD, 3217.77' TVD
7 4418.51 12.00 7.00 4073.65 1484.00 100.00 0.00 0.00 1487.07
8 7400.00 12.00 7.00 6989.99 2099.27 175.55 0.00 0.00 2106.58 Total Depth : 7400' MD, 6989.99' TVD
0
150
300
450
600
750
900
1050
1200
1350
1500
1650
1800
1950
2100
2250
2400
2550
South(-)/North(+) (300 usft/in)-450 -300 -150 0 150 300 450 600 750 900 1050 1200 1350 1500 1650
West(-)/East(+) (300 usft/in)
BRU 223-34 wp09 tgt1
13 3/8" Casing
9 5/8" x 12 1/4"
4 1/2" x 6 3/4"
250500
7 5 0
1 0 0 0
1250
1500
1750
2000
2250
2500
2750
3000
3250
3500
3750
4000
4250
4500
4750
5000
5250
5500
5750
6000
6250
6500
6750
6990
BRU 223-34 wp09
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 3.5º/100' : 750' MD, 744.31'TVD
End Dir : 1397.72' MD, 1341.17' TVD
Start Dir 3º/100' : 2894.43' MD, 2617.73'TVD
End Dir : 3543.51' MD, 3217.77' TVD
Total Depth : 7400' MD, 6989.99' TVD
CASING DETAILS
TVD TVDSS MD Size Name
110.00 6.80 110.00 13-3/8 13 3/8" Casing
2563.00 2459.80 2830.26 9-5/8 9 5/8" x 12 1/4"
6989.99 6886.79 7400.00 4-1/2 4 1/2" x 6 3/4"
Project: Beluga River
Site: BRU C-Pad
Well: BRU 223-34
Wellbore: BRU 223-34
Plan: BRU 223-34 wp09
WELL DETAILS: BRU 223-34
84.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 2619657.30 315276.20 61° 9' 58.0856 N
151° 2' 46.1626 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well BRU 223-34, True North
Vertical (TVD) Reference:As-Staked RKB @ 103.20usft (HEC 147)
Measured Depth Reference:As-Staked RKB @ 103.20usft (HEC 147)
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:BRU 223-34 NAD 1927 (NADCON CONUS)Alaska Zone 0484.70+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002619657.30 315276.20 61° 9' 58.0856 N151° 2' 46.1626 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well BRU 223-34, True NorthVertical (TVD) Reference:As-Staked RKB @ 103.20usft (HEC 147)Measured Depth Reference:As-Staked RKB @ 103.20usft (HEC 147)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-04-24T00:00:00 Validated: Yes Version: Depth From Depth ToSurvey/PlanTool18.50 2830.00 BRU 223-34 wp09 (BRU 223-34) 3_MWD+AX+Sag2830.00 7400.00 BRU 223-34 wp09 (BRU 223-34) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Measured Depth (850 usft/in)BRU 224-34BRU 242-04GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference18.50 To 7400.00Project: Beluga RiverSite: BRU C-PadWell: BRU 223-34Wellbore: BRU 223-34Plan: BRU 223-34 wp09CASING DETAILSTVD TVDSS MD Size Name110.00 6.80 110.00 13-3/8 13 3/8" Casing2563.00 2459.80 2830.26 9-5/8 9 5/8" x 12 1/4"6989.99 6886.79 7400.00 4-1/2 4 1/2" x 6 3/4"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in 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 STERLING-BELUGA GAS
223-041
Beluga River Unit 223-34
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BELUGA RIV UNIT 223-34Initial Class/TypeDEV / PENDGeoArea820Unit50220On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230410BELUGA RIVER, STRLG-BELUGA GAS - 92500NA1 Permit fee attachedYes Surface Location lies within ADL0029656; Top Prod Int & TD lie within ADL0029657.2 Lease number appropriateYes3 Unique well name and numberYes BELUGA RIVER, Sterling-Beluga Gas Pool – 92500, governed by CO 802, issued May 5, 20224 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2401 psi, BOP rated to 5k psi (BOP tets to 3500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated based on offset wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected Pressure Range is 0.12 to 0.443 psi/ft (2.3 to 8.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability. Principal hazards include37 Seismic analysis of shallow gas zonesNA circulation, wellbore instability, and running coal seams. LCM materials will be available onsite. Mitigation38 Seabed condition survey (if off-shore)NA measures are discussed in the Anticipated Drilling Hazards section of application.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/28/2023ApprBJMDate5/30/2023ApprSFDDate5/28/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 05/30/23JLC 5/30/2023
