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7. Property Designation (Lease Number):
1. Operations
Performed:
2. Operator Name:
3. Address:
4. Well Class Before Work:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
Susp Well Insp
Install Whipstock
Mod Artificial Lift Perforate New Pool
Perforate
Plug Perforations
Coiled Tubing Ops
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well Other:
Change Approved Program
Operations shutdown
11. Present Well Condition Summary:
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
16. Well Status after work:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
OIL GAS
WINJ WAG GINJ
WDSPL
GSTOR Suspended SPLUG
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
PBU Z-235
Gel Squeeze
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
223-055
50-029-23760-00-00
11920
Conductor
Surface
Intermediate Tiebac
Liner / Slotted Liner
4866
80
8016
6713
5194
11918
20"
9-5/8"
7"
7" X 4-1/2"
4866
27 - 107
26 - 8042
23 - 6736
6726 - 11920
27 - 107
26 - 4895
23 - 4531
4526 - 4866
None
3090
5410
5410
None
5750
7240
7240
8144 - 11722
4-1/2" 12.6# L-80 22 - 7973
4897 - 4865
Structural
4-1/2" HES TNT Perm Packer
6761
4544
Torin Roschinger
Operations Manager
Tyson Shriver
tyson.shriver@hilcorp.com
907-564-4542
PRUDHOE BAY, Schrader Bluff Oil, Orion Dev Area
Total Depth
Effective Depth
measured
true vertical
feet
feet
feet
feet
measured
true vertical
measured
measured
feet
feet
feet
feet
measured
true vertical
Plugs
Junk
Packer
Measured depth
True Vertical depth
feet
feet
Perforation depth
Tubing (size, grade, measured and true vertical depth)
Packers and SSSV
(type, measured and true vertical depth)
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.Representative Daily Average Production or Injection Data
Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation:
Subsequent to operation:
15. Well Class after work:
Exploratory Development Service StratigraphicDaily Report of Well Operations
Copies of Logs and Surveys Run
Electronic Fracture Stimulation Data
Sundry Number or N/A if C.O. Exempt:
ADL 0028262
22 - 4889
Slotted Liner 8144 - 11722'MD
Pump 25-bbls Equiseal gel at 600-psi.
957
520
0
0
503
135
325-488
13b. Pools active after work:Schrader Bluff Oil, Orion Dev Area
No SSSV Installed
6761, 4544
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
Sr Pet Eng: Sr Pet Geo:
Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Sr Res Eng:
Due Within 30 days of Operations
By Grace Christianson at 10:43 am, Oct 09, 2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.10.09 05:01:01 -
08'00'
Torin Roschinger
(4662)
J.Lau 11/10/25
RBDMS JSB 101625
ACTIVITY DATE SUMMARY
9/9/2025
T/I/O=835/0/0, LRS Unit 76, Pumped 191 bbls green dyed KCL down TBG. Grabbed
baseline sample from Z-229 at 48 bbls pumped, Pumped an additional 713 bbls 1%
KCL. Never saw green dye at Z-229 wellhead. Pumped 38 bbls 60/40 methanol to
FP. Pumped 4 bbls 60/40 methanol down FL to FP. RDMO FWHP's = 0/0/0 SV,
WV, SSV = closed. MV = open. IA and OA = OTG.
9/10/2025
T/I/O = 410/VAC/VAC. Temp = SI. T FL (FB). T FL @ 4120' (4024' above slotted
liner).
SV, WV, SSV = C. MV = O. IA, OA = OTG. 17:30
9/11/2025
T/I/O = 560/0/0 Pumped 250 bbls of 1% KCl prefluhs, followed by 101 bbls 1 %
KCl/dye (red) down TBG, followed by 296 bbls 1% KCl.while sampling at wellhead of
Z-229. Start to see signs of tracer at 515 bbls away. Lab to take samples and spin
out. Freeze protected TBG with 45 bbls of 60/40.
Valve Positions - SV/WV/SSV= Closed, MV= Open, IA/OA= OTG
FWHPs= 0/0/0
9/21/2025
T/I/O=950/0/0 SBG Treatment ( Reservoir Sweep ) Pump 3 bbls 60/40, 128 bbls
SBG, & 1 bbl 60/40 down tbg. Soak for 3 hrs. Pump 98 bbls 1% kcl flush down Tbg.
Pumped an additional 49 bbls 1% KCL and a 52 bbl DSL FP down Tbg after 2nd 3
hour soak. Pad Op notified of well status per LRS departure. SV,WV,SSV=C MV=O
IA,OA=OTG
9/24/2025
T/I/O= 360/0/0 (RESERVOIR SWEEP MOD) Loaded well with 290 bbls of 1% KCl.
Freeze protected Z-229 TBG with 26 bbls of Crude and FL with 4 bbls of 60/40.
Pumped 60 bbls of 1% KCl down TBG due to KCl being too warm for gel. Pumped
the following per procedure - 25 bbls of Equiseal, 5 bbls of 1% KCl, and 120 bbls of
90* Diesel at specified rates. See log. ***Job Continued to 09-25-2025***
***Fire Drill Complete***
9/25/2025
***Continue Job from 09-24-2025*** Assist w/ Gel Squeeze (RESERVOIR SWEEP
MOD) Pumped additional 20 bbls Diesel into TBG in attempt to catch pressure after
fluid log. Well still on vac. DHD in control of well and Pad-Op notified upon LRS
departure.
Daily Report of Well Operations
PBU Z-235
7. If perforating:
1. Type of Request:
2. Operator Name:
3. Address:
4. Current Well Class:5. Permit to Drill Number:
6. API Number:
8. Well Name and Number:
9. Property Designation (Lease Number):10. Field:
Abandon
Suspend
Plug for Redrill Perforate New Pool
Perforate
Plug Perforations
Re-enter Susp Well
Other Stimulate
Fracture Stimulate
Alter Casing
Pull Tubing
Repair Well
Other:
Change Approved Program
Operations shutdown
What Regulation or Conservation Order governs well spacing in thes pool?
Will perfs require a spacing exception due to property boundaries?Yes No
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
PRESENT WELL CONDITION SUMMARY
Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft):
Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft):
Casing Length Size MD TVD Burst Collapse
Exploratory
Stratigraphic
Development
Service
12. Attachments:
14. Estimated Date for
Commencing Operations:
13. Well Class after proposed work:
15. Well Status after proposed work:
16. Verbal Approval:
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal.
Proposal Summary Wellbore schematic
BOP SketchDetailed Operations Program
OIL
GAS
WINJ
WAG
GINJ
WDSPL
GSTOR
Op Shutdown
Suspended
SPLUG
Abandoned
ServiceDevelopmentStratigraphicExploratory
Authorized Name and
Digital Signature with Date:
Authorized Title:
Contact Name:
Contact Email:
Contact Phone:
AOGCC USE ONLY
Commission Representative:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Location ClearanceMechanical Integrity TestBOP TestPlug Integrity
Other Conditions of Approval:
Post Initial Injection MIT Req'd?Yes No
Subsequent Form Required:
Approved By:Date:
APPROVED BY
THE AOGCCCOMMISSIONER
PBU Z-235
Gel Squeeze
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage,
AK 99503
223-055
50-029-23760-00-00
N/A
ADL 0028262
11920
Conductor
Surface
Intermediate Tiebac
Liner / Slotted Liner
4866
80
8016
6713
5194
11918
20"
9-5/8"
7"
7" X 4-1/2"
4866
27 - 107
26 - 8042
23 - 6736
6726 - 11920
1660
27 - 107
26 - 4895
23 - 4531
4526 - 4866
None
3090
5410
5410
None
5750
7240
7240
8144 - 11722 4-1/2" 12.6# L-80 22 - 79734897 - 4865
Structural
4-1/2" HES TNT Perm Packer
No SSSV Installed
6761, 4544
No SSSV Installed
Date:
Torin Roschinger
Operations Manager
Tyson Shriver
tyson.shriver@hilcorp.com
907-564-4542
PRUDHOE BAY
9/2/2025
Current Pools:
Schrader Bluff Oil, Orion Dev Area
Proposed Pools:
Schrader Bluff Oil, Orion Dev Area
Suspension Expiration Date:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng
Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:34 pm, Aug 19, 2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.08.19 11:20:36 -
08'00'
Torin Roschinger
(4662)
325-488
10-404
DSR-8/19/25JJL 8/21/25
SFD 8/25/2025JLC 8/25/2025
Gregory C. Wilson Digitally signed by Gregory C. Wilson
Date: 2025.08.25 16:16:21 -08'00'08/25/25
RBDMS JSB 082725
Gel Squeeze
PBU Z-235
PTD:223-055
Well Name:Z-235i API Number:50-029-23760-00
Current Status:Operable – WAG Injector (SI)Permit to Drill #:223-055
Estimated Start Date:September 2025 Rig:FB
Reg.Approval Req’std?10-403 Estimated Duration:3Days
Regulatory Contact:Abbie Barker Date Reg. Approval
Rec’vd:
First Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M)
Second Call Engineer:Hunter Gates (215) 498-7274 (M)
Current Bottom Hole Pressure:2,100 psi @ 4,400’ TVD 5/2025 FL Shot
Max. Anticipated Surface Pressure:1,660 psi (Based on 0.1 psi/ft gas gradient)
Last SI WHP:470 psi (Taken on 1/6/2022)
Min ID:3.813” X-Nipple 2,957’ MD
Max Angle:98 Deg @ 10,467’ MD
Brief Well Summary:
Z-235 is a Schrader Bluff single lateral OBc WAG injector that was drilled in August 2023. The well supports
offset, up dip producer, Z-229. In August 2024, Z-235 was WAG’d to PWI and an immediate response was seen
at Z-229. The previous PWI slug injected from March to June 2024 did not show rapid communication with Z-
229.
Z-235 was drilled across two east-west faults and contains an un-isolated plug back approximately mid-lateral
at 9,158’ MD. Two IPROFs on PWI were run in Z-235 to understand where injection was leaving the pipe. The
first IPROF came back with limited to no spinner data so a second IPROF was performed which showed ~90% of
the liquid exiting the first four slotted liner joints in the heel between 8,144’ to 9,089’ MD. This would imply
that Fault #1 at 8,512’ MD has broken down and is providing a quick connection between Z-235 and Z-229. Z-
229 crosses the same fault.
Being an open hole slotted liner completion, conformance repair options are limited. Milne Point has had
success injecting Halliburton EquiSeal gel into MBEs or MBE like channels and plugging them off. A
conformance squeeze with the Equiseal gel will be attempted to repair the probable fault communication
between Z-235 and Z-229.
Objective:
- Fingerprint the MBE / fault volume by pumping Red Dye into Z-235 and monitoring for returns at Z-229.
- Inject EquiSeal gel to seal up MBE / fault.
Well Status
OPERABLE, WAG injector, SI. No integrity issues.
Recent Integrity:
> 09/11/23: AOGCC MIT-IA Passed to 2430 psi
> 09/03/23: Pull B&R
> 08/13/23: Rig MIT-T passed to 3510 and MIT-IA passed to 3552 psi
Gel Squeeze
PBU Z-235
PTD:223-055
WBL Steps:
1 F INJECT RED DYE INTO Z-235 TO VERIFY QUICK CONNECT IS STILL PRESENT BETWEEN Z-235 & Z-
229 AND FINGERPRINT FAULT / MBE VOLUME.
2 F INJECT EQUISEAL GEL INTO FORMATION TO PLUG UP FAULT / MBE CONNECTION.
3 CP CLEANOUT ANY GEL REMAINING IN THE LINER.
Procedural Steps:
Fullbore
NOTE 1:Prior to FB arrival, have PCC place Z-229 in the pad test separator. Ensure well has been in the
separator for a minimum of 2-hrs prior to pumping on well so baseline production rates can be established.
Contact OE and let them know when pumping will commence.
NOTE 2:Prior to the job, coordinate with lab samplers / operations on pulling frequent samples at the producer
(Z-229) during injection.
1. MIRU FB. The following fluids need to be on location for injection:
a. Vac truck with 200 bbls of 1% KCl w/ 6 gallons of Red Dye mixed in.
b. 2x uprights (or vac trucks) loaded with 580 bbl of 1% KCl
2. Take a picture of the Red Dye sample before it is injected.
3. Begin loading well from vac truck with Red Dye mixture. Inject at 5 bpm or max rate. Do not exceed
1,600 psi.
a. Have OE and PCC monitor Z-229 in test separator for signs of increased water production while
injecting KCl into Z-235.
4. After Red Dye vac truck is emptied, switch over to pumping clean KCl from upright.
5. Continue injecting additional 580 bbls of 1% KCl at 5 bpm or max rate.
a. Begin sampling Z-229 at the wellhead for Red Dye returns once 1% KCL is being pumped.
i. If too much gas is being produced at Z-229 which makes sampling unsafe, an
alternative sample location is from the liquid leg of the pad test separator.
b. Samples should continue to be pulled every 10 minutes until either Red Dye is being returned
from Z-229 or 580 bbls of clean KCl has been pumped.
c. Utilize Sampling Sheet in the attachments of this procedure to track Red Dye. Once 3x
consecutive samples of Red Dye have been captured at the test separator, no further sampling
is required. Take pictures of the captured Red Dye samples. Send completed sample sheet and
pictures of Red Dye, pre and post, to OE (tyson.shriver@hilcorp.com).
d. The results of this diagnostic pumping will be used to size the gel treatment volume.
6. Once all water is pumped off surface, FP well w/ 38 bbls 60/40 MeOH and RDMO.
Well Diagnostics
1. Approximately 24-hrs after Red Dye pumping is complete, shoot tubing fluid level and capture SIWHP.
a. This step will help determine final hydrostatics after Equiseal gel is pumped.
Operations
1. Shut-in Z-229 when fullbore arrives on location to pump gel treatment.
Fullbore
NOTE:Prior to rig up, ensure operations has shut-in offset producer Z-229. Do not want Z-229 on production
when injecting gel into Z-235.
NOTE:Confirm final volume of Equiseal gel and freeze protect with OE prior to loading out job.
1. MIRU FB pump truck and Halliburton cement van.
Gel Squeeze
PBU Z-235
PTD:223-055
2. Ahead of pumping gel treatment, fullbore truck to load well with 180 bbls 1% KCl. Pump at max rate,
not to exceed 1,600 psi WHP.
3. Pump the following gel treatment down the tubing at 2 bpm keeping pressure below 1,600 psi.
a. 45 bbls of Equiseal – catch sample of the gel in a Nalgene bottle and leave in the wellhouse.
Halliburton cement van to pump Equiseal.
b. 101 bbls of 1% KCl – displacement volume may be adjusted based on previous fullbore
pumping operations. Confirm with OE. Displacement to be pumped with fullbore truck.
c. 38 bbls 60/40 MeOH
4. Drop rate to 1 bpm with 15 bbls of freeze protect left to pump
5. Drop rate to 0.5 bpm with 5 bbls of freeze protect left to pump
6. Shut down once displacement and freeze protect volume has been pumped.
a. Displacement volume plus freeze protect spots the tail edge of the Equiseal at the bottom of
Slot #10, 9,089’ MD.
7. RDMO FB pump truck and Halliburton cement van.
Operations
1. Check sample every 12-hrs. Send pictures/video of gel to OE. Z-229 should not be RTP’d until gel will
NOT flow out of sample bottle. Anticipate this being between 24-48 hrs.
2. When Z-229 is returned to production, an extended SLBU procedure should be executed.
3. Prior to POI’ing Z-235, let gel set up for a minimum of 3 days. Work with OE on timing for POI.
4. Attempt to put well on PW injection at a target rate of 2,000 bwpd, but no more than 1,150 psi. Rate
should be walked up slowly ~300 bwpd increments for 30 minutes each.
a. There is a small possibility that the Equiseal has formed a plug in the liner and will need to be
jetted out with coil.
Coiled Tubing – Pending
1. MIRU CTU.
2. MU and RIH with JSN and jet through Equiseal gel with 1% KCl.
a. Worst case scenario if all Equiseal stayed in the wellbore, it could be down to PBTD at 11,918’
MD.
3. Once all gel has been cleaned out, POOH and RDMO. Hand well over to OPS to POI.
Attachments:
x Wellbore Schematic
x Sampling Sheet
x Sundry Change Form
Gel Squeeze
PBU Z-235
PTD:223-055
Wellbore Schematic:
Gel Squeeze
PBU Z-235
PTD:223-055
Sampling Sheet:
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Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Work Over Sundry ProcedureDate: August 19, 2025Subject: Changes to Approved Sundry Procedure for Well Z-235Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the workover (WO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDate Procedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/15/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250515
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 241-23 50283201910000 223061 4/24/2025 AK E-LINE Plug/Perf
T40412
END 2-72 50029237810000 224016 4/4/2025 READ CoilFlag
T40413
IRU 241-01 50283201840000 221076 4/30/2025 AK E-LINE Perf
T40414
IRU 241-01 50283201840000 221076 4/23/2025 AK E-LINE Plug/Perf
T40414
KU 33-08 50133207180000 224008 4/22/2025 AK E-LINE PPROF
T40415
MRU D-16RD 50733201830100 180110 4/21/2025 AK E-LINE Cement/Perf
T40416
NSU NS-06 50029230880000 202101 4/21/2025 AK E-LINE PPROF
T40417
NSU NS-19 50029231220000 202207 4/27/2025 AK E-LINE Perf
T40418
NSU NS-20 50029231180000 202188 4/24/2025 AK E-LINE Perf
T40419
NSU NS-23 50029231460000 203050 4/23/2024 AK E-LINE Packer
T40420
PBU 02-10B 50029201630200 200064 3/21/2025 BAKER SPN
T40421
PBU 06-19B 50029207910200 224095 3/1/2025 BAKER MRPM Borax
T40422
PBU S-100A 50029229620100 224083 2/28/2025 BAKER MRPM Borax
T40423
PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile
T40424
SRU 231-33 50133101630100 223008 5/1/2025 AK E-LINE Plug/Perf
T40425
Revision Explanation: Processing report added
Please include current contact information if different from above.
T40424PBU Z-235 (Revised)50029237600000 223055 4/1/2025 READ InectionProfile
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.16 08:15:21 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/22/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#2025022
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL
BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf
BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP
BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf
MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL
MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL
MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut
NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf
NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf
PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile
HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL
HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40328
T40329
T40330
T40331
T40332
T40333
T40334
T40335
T40336
T40337
T40338
T40339
PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.28 08:42:09 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 1/07/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240107
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset #
END 2-72 50029237810000 224016 11/16/2024 HALLIBURTON TEMP
END 2-74 50029237850000 224024 12/5/2024 HALLIBURTON MFC24
END 2-74 50029237850000 224024 8/13/2024 DarkVision HADES (Down hole camera)
KGSF 1A 50133101600100 220063 12/5/2024 HALLIBURTON EPX-MFC40
MPU F-13 50029225490000 195027 12/22/2024 HALLIBURTON WFL-TMD3D
PU F-40 50029222150000 191117 11/9/2024 READ CaliperSurvey
MPU I-04A 50029220680100 201092 11/22/2024 HALLIBURTON COILFLAG
MPU J-02 50029220710000 190096 12/22/2024 READ CaliperSurvey
PBU L-04 50029233190000 206120 11/23/2024 HALLIBURTON WFL-TMD3D
PBU L-221 50029233850000 208031 12/11/2024 HALLIBURTON WFL-RMT3D
PBU Z-ϯϰ 50029234690000 212061 12/15/2024 HALLIBURTON WFL-RMT3D
PBU Z-2ϯϱ 50029237600000 223055 9/24/2024 READ InjectionProfile
PBU Z-ϮϮϯ 50029237200000 222080 11/24/2024 HALLIBURTON WFL-TMD3D
SCU 42-05Y 50133205700000 207082 12/7/2024 HALLIBURTON EPX-MFC24
TBU D-16RD 50733201830100 180110 12/19/2024 READ CaliperSurvey
TBU D-17RD 50733201680100 181023 12/21/2024 READ CaliperSurvey
Please include current contact information if different from above.
T39915
T39916
T39916
T39917
T39918
T39919
T39920
T39921
T39922
T39923
T39924
T39925
T39926
T39927
T39928
T39929
PBU Z-2ϯϱ 50029237600000 223055 9/24/2024 READ InjectionProfile
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.01.07 15:26:55 -09'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 10/04/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20241004
Well API #PTD #Log Date Log Company Log Type AOGCC
Eset#
BRU 214-13 50283201870000 222117 9/26/2024 AK E-LINE Perf
END 2-72 50029237810000 224016 8/26/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 8/29/2024 HALLIBURTON RBT
MPI 2-16 50029218850000 188134 9/9/2024 AK E-LINE Perf
MPI 2-16 50029218850000 188134 9/20/2024 AK E-LINE Perf
MPU B-16 50029213840000 185149 9/28/2024 READ CaliperSurvey
MPU B-24 50029226420000 196009 8/20/2024 HALLIBURTON PERF
MPU B-28 50029235660000 216027 9/28/2024 HALLIBURTON TUBINGCUT
MPU I-01 50029220650000 190090 8/17/2024 HALLIBURTON PERF
MPU R-103 50029237990000 224114 9/20/2024 AK E-LINE Hoist
MRU M-02 50733203890000 187061 9/23/2024 AK E-LINE Perf
PBU 02-21B 50029207810200 211033 9/30/2024 HALLIBURTON RBT
PBU L2-10 50029217460000 187085 8/23/2024 HALLIBURTON RBT
PBU L-212 50029232520000 205030 9/24/2024 HALLIBURTON IPROF
PBU L-254 50029237520000 223030 9/20/2024 HALLIBURTON IPROF
PBU P1-17 50029223580000 193051 9/7/2024 HALLIBURTON RBT
PBU S-09A 50029207710100 214097 8/21/2024 HALLIBURTON RBT
PBU Z-235 50029237600000 223055 9/19/2024 HALLIBURTON IPROF
Please include current contact information if different from above.
T39619
T39620
T39620
T39620
T39621
T39621
T39622
T39623
T39624
T39625
T39626
T39627
T39628
T39629
T39630
T39631
T39632
T39633
T39634PBU Z-235 50029237600000 223055 9/19/2024 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.10.04 15:10:24 -08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, October 17, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
Z-235
PRUDHOE BAY UN ORIN Z-235
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 10/17/2023
Z-235
50-029-23760-00-00
223-055-0
G
SPT
4544
2230550 1500
1729 1734 1730 1730
102 425 425 425
INITAL P
Austin McLeod
9/11/2023
PKR TVD taken from directional survey.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UN ORIN Z-235
Inspection Date:
Tubing
OA
Packer Depth
263 2490 2447 2430IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM230911184922
BBL Pumped:1.4 BBL Returned:1.6
Tuesday, October 17, 2023 Page 1 of 1
"
By Grace Christianson at 9:16 am, Sep 06, 2023
Completed
8/13/2023
JSB
RBDMS JSB 091523
G
DSR-9/25/23
Drilling Manager
09/05/23
Monty M
Myers
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.09.05 16:48:31 -08'00'
Torin
Roschinger
(4662)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU Z-235 Date:8/6/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Barber/Amend
Csg Setting Depth:8043 TMD 4894 TVD
Mud Weight:9.2 ppg LOT / FIT Press =713 psi
LOT / FIT =12.00 ppg Hole Depth =8150 md
Fluid Pumped=1.6 Volume Back =1.5 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->245 ->0
->4 109 ->8277
->6 153 ->16 554
->8 217 ->24 831
->10 276 ->30 1039
->12 334 ->36 1246
->14 393 ->40 1385
->16 454 ->46 1592
->18 512 ->50 1731
->20 570 ->60 2078
->22 621 ->70 2424
->24 672 ->77 2667
->26 720 ->
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 720 ->0 2667
->1 697 ->1 2660
->2 683 ->2 2657
->3 672 ->3 2655
->4 664 ->4 2654
->5 655 ->5 2652
->6 649 ->10 2645
->7 642 ->15 2640
->8 635 ->20 2635
->9 630 ->25 2631
->10 623 ->30 2627
->11 620 ->
->13 ->
->15 ->
2
4
6
8
10
12
14
16
18
20
22
24
26
8
16
24
30
36
40
46
50
60
70
77
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 102030405060708090
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
720697683672664655649642635630623620
266726602657265526542652 2645 2640 2635 2631 2627
0
100
200
300
400
500
600
700
800
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Activity Date Ops Summary
7/25/2023 Spot sub base, catwalk, and pipeshed. Spot and shim mud mod and gen mod. Adjust pipeshed. Trucks released at 21:00. Rig up interconnects. Spot auxiliary
equipment. Replace man rider and tugger line in derrick. Work on rig acceptance checklist. Rebuild coolant line system for mud pump t. Cont. working on rig
acceptance checklist, C/O derrick climber cable. Remove links from drag chain and C/O bad paddles. Safe out walkways and post rig move inspections. Scope
up derrick, Bridle down. Cont. working on rig acceptance checklist. Pick up MPD test cap and install. N/D RCD from BOP stack.
7/26/2023 Cont. pulling RCD off BOP stack. N/U diverter system: Set stack on diverter 'T'. Install bell nipple on stack Install knife valve and diverter vent sections. Install flow
riser and air up boots. Add nitrogen to accumulator bottles. SimOps: Open up TD coffin. Add nitrogen to counter balance. Adjust hydraulics. Ad glycol to mud
pump 1. Function test all equ. Cont. with rig acceptance checklist. Trouble shoot and adjust stand jump and overhead spinners. Install mousehole. Obtain RKB's.
Rig accepted at 16:30. Pick up, drift (3.125" OD) and rack back 250 joints of drill pipe. Pick up, drift (2.75") and rack back 17 joints HWDP and jars. Change out
drilling line. Hang blocks. Pull new/old drill line tails to rig floor. Remove dead line anchor. Attach lewis cable snake as per procedure. Remove mechanical crown
saver, C/O drill line, snaking through crown sheaves and blocks. Spool old line off drawworks, spool new line on drawworks.
7/27/2023 Grease and inspect crown sheaves. Service TDS and traveling equipment. Perform monthly EAM crown sheave. Perform diverter test w/ 5" DP. Knife valve open
5 secs, Annular close 11 secs. Drawdown - 3000 initial psi, 2000 drawdown psi, 200 psi increase 18 secs, Full charge @ 57 secs. 2275 psi 6 bottle avg nitrogen.
Test gas alarms 20/40% LEL, 10/20 ppm H2S. Check PVT system and alarms (good). AOGCC rep Sean Sullivan waived witness via email @ 16:55 7/26/2023.
Email in "O' drive well file. Mobilize BHA components to rig floor. PJSM, M/U 12-1/4" Kymera w/ 8" mtr. Dry tag @ 37' MD. Flood conductor and check for leaks
(good). P/T mud lines to 3K (good). Wash down to 37'. Drill 12-1/4" rathole F/ 37' - T/ 220' MD. Observed formation @ shakers 119' MD w/ minimal
parameters.350 gpm, 220 psi, 30 rpm, 1-5k tq. Heavy sand w/ some pea gravel. S/O 44k, P/U 45k, ROT 44k. 80 bbls loss during drilling interval. CBU, BROOH
1x std, POOH to surface. Inspect bit (good). M/U MWD tools w/ 12-1/4" 633 Kymera, 8" -1.5 Mtr assy (non port float). Upload MWD. M/U 2x 8" NM Flex DCs, Btl
.neck XO,6x 5" NC50 HWDP, 6-1/3" Hydra Jars, 11x 5" NC50 HWDP. Total length 716.27'. Shallow pulse test (good). Wash down to 220'. Drill 12-1/4" surface
hole from 220' to 306' (total 86', AROP 25 fph) at 375-425 gpm, 670 psi, slide 100%, ECD 9.8 ppg with 8.8 ppg mud, WOB 5K, P/U 58K, S/O 55K, ROTW 55K.
Continually jet flowline, pump through bleeder as needed. Clear out packed off dragchain x 2. Loss rate 40 bph. Drill 12-1/4" surface hole from 306' to 652' (total
346', AROP 58 fph) at 375-425 gpm, 710 psi, 30 rpms, 1800 ft-lbs, ECD 9.8 ppg with 8.8 ppg mud, WOB 5-10K, P/U 64K, S/O 55K, ROTW 58K. Continually jet
flowline, pump through bleeder as needed. ~90-95% sliding. Loss rate 5-1 bph. Drill 12-1/4" surface hole from 652' to 1129' (total 477', AROP 80 fph) at 375-425
gpm, 1047psi, 70 rpms, 4000 ft-lbs, ECD 9.8 ppg with 9.0 ppg mud, WOB 5-10K, P/U 75K, S/O 71K, ROTW 73K. Continually jet flowline, pump through bleeder
as needed. Slide as needed for 4/100 build. Last gyro survey at 739'. Distance to WP 3: 24.75', 14.16' low, 6.53' left. Daily downhole losses 280 bbls, total 280
bbls.
7/28/2023 Drill 12-1/4" surface hole from 1129' to 1794' (total 665', AROP 111 fph) at 450 gpm, 1250 psi, 50 rpms, 5-7Kft-lbs, ECD 10.2 ppg with 9.2 ppg mud, WOB 8-
13K, P/U 82K, S/O 71K, ROTW 76K. Max gas 39u. Slide as needed to maintain tangent inclination starting @ 1574' MD. BR full stands. Drill 12-1/4" surface hole
from 1794' to 2363' (total 569', AROP 95 fph) at 375-450 gpm, 1039 psi, 50 rpms, 6-8Kft-lbs, ECD 10.49 ppg with 9.5 ppg mud, WOB 7-15K, max gas 84u. P/U
88K, S/O 68K, ROTW 80K. Slide as needed to maintain tangent inclination. Jet flowline as needed. BR full stands. Base of Permafrost logged at 2282'md. Drill 12-
1/4" surface hole from 2363' to 3002' (total 639', AROP 107 fph) at 475 gpm, 1366 psi, 80 rpms, 7-10Kft-lbs, ECD 11.21 ppg with 9.55 ppg mud, WOB 7-13K,
max gas 2030U. P/U 103K, S/O 74K, ROTW 80K. Slide as needed to maintain tangent. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from
3002' to 3765' (total 763', AROP 127 fph) at 475-500 gpm, 1585 psi, 80 rpms, 6-8Kft-lbs, ECD 10.56 ppg with 9.55 ppg mud, WOB 6-11K, max gas 3193u. P/U
116K, S/O 76K, ROTW 92K. Slide as needed to maintain tangent. Jet flowline as needed. BR full stands. Distance to WP3: 3.54', 3.43' high, 0.89' right. Daily
fluid lost to formation 0 bbls, total 280 bbls.
7/29/2023 Drill 12-1/4" surface hole from 3765' to 4465' (total 700', AROP 117 fph) at 475-525 gpm, 2025 psi, 80 rpms, 8-10Kft-lbs, ECD 11.08 ppg with 9.65 ppg mud,
WOB 5-13K, max gas 3620u. P/U 128K, S/O 74K, ROTW 93K. Slide as needed to maintain tangent. Jet flowline as needed. BR full stands. Drill 12-1/4" surface
hole from 4465' to 4944' (total 479', AROP 80 fph) at 375-475 gpm, 2280 psi, 80 rpms, 12-14Kft-lbs, ECD 10.78 ppg with 9.75 ppg mud, WOB 5-13K, max gas
2667u. P/U 148K, S/O 81K, ROTW 103K. Slide as needed to maintain tangent. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from 4944' to
5420' (total 476', AROP 80 fph) at 475 gpm, 1985 psi, 80 rpms, 12-15Kft-lbs, ECD 10.41 ppg with 9.5 ppg mud, WOB 7-17K, max gas 2894u. P/U 151K, S/O
85K, ROTW 109K. Slide as needed to maintain tangent. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from 5420' to 5927' (total 507', AROP 85
fph) at 525 gpm, 2075 psi, 80 rpms, 14-17Kft-lbs, ECD 10.45 ppg with 9.5 ppg mud, WOB 5-12K, max gas 3002u. P/U 169K, S/O 82K, ROTW 114K. Start
4/100' build/turn at 5712'. Jet flowline as needed. BR full stands. Distance to WP3: 2.93', 2.93' high, 0.02' Right. Daily fluid lost to formation 0 bbls, total 280 bbls.
7/30/2023 Drill 12-1/4" surface hole from 5927' to 6308' MD / 4299' TVD (total 381', AROP 64 fph) 525 gpm, 2005 psi, 80 rpm, 14-16Kft-lbs, ECD 10.26 ppg w/ 9.5 ppg
mud, WOB 3-10K, max gas 2304u. P/U 153K, S/O 88K, ROT 114K. Start 4/100' build/turn at 5712'. Jet flowline as needed. BR full stands. Drill 12-1/4" surface
hole from 6308' to 6542' MD / 4426' TVD (total 234', AROP 39 fph) 525 gpm, 1781 psi, 100% sliding, ECD 10.02 ppg w/ 9.45 ppg mud, WOB 20-25K, max gas
1733u. P/U 178K, S/O 88K, ROT 114K. Slide for 4/100' build/turn at 5712'. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from 6542' to 6882'
MD / 4577' TVD (total 340', AROP 57 fph) 525 gpm, 2010 psi, 100% sliding, ECD 10.1 ppg w/ 9.45 ppg mud, WOB 12-14K, max gas 1870u. P/U 185K, S/O
88K, ROT 114K. Slide for 4/100' build/turn at 5712'. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from 6882' to 7262' MD / 4726' TVD (total
380', AROP 63 fph) 525 gpm, 2055 psi, 80 rpms, 17Kft-lbs , ECD 10.28 ppg w/ 9.5 ppg mud, WOB 8-22K, max gas 1815u. P/U 177K, S/O 84K, ROT 122K.
Slide for 4/100' build/turn at 5712'. Jet flowline as needed. BR full stands. Distance to WP3: 15.59', 15.46' high, 2.01' left. Daily fluid lost to formation 0 bbls, total
280 bbls.
50-029-23760-00-00API #:
Well Name:
Field:
County/State:
PBW Z-235
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
7/27/2023Spud Date:
7/31/2023 Drill 12-1/4" surface hole from 7262' to 7518' MD / 4806' TVD (total 256', AROP 73 fph) 525 gpm, 2125 psi, 80 rpms, 17Kft-lbs, ECD 10.31 ppg w/ 9.5 ppg mud,
WOB 8-18K, max gas 1767u. P/U 174K, S/O 91K, ROT 122K. Slide for 4/100'. Jet flowline as needed. BR full stands. Service rig: Observe top drive leak. Rack
stand back. Open up coffin and tighten fitting while circulating 3 bpm 475 psi. Observe fluid coming out of weep hole on Pod 2, mud pump 1. Chance out pod
while slowly BROOH to 7329' at 315 gpm, 875 psi, 40 rpms, 16.5Kft-lbs. Max gas 1757u. P/U 183K, S/O 90K, ROT 121K. Wash down to bottoms at 7518'. Drill
12-1/4" surface hole from 7518' to 7708' MD (total 190', AROP 42 fph) 525 gpm, 2125 psi, 80 rpms, 17Kft-lbs, ECD 10.31 ppg w/ 9.5 ppg mud, WOB 8-18K, max
gas 1901u. P/U 185K, S/O 90K, ROT 122K. Slide for 4/100' build/turn. Jet flowline as needed. BR full stands. Drill 12-1/4" surface hole from 7708' to TD at 8050'
MD (total 342', AROP 76 fph) 525 gpm, 2136 psi, 80 rpms, 18-20Kft-lbs, ECD 10.41 ppg w/ 9.55 ppg mud, WOB 8-14K, max gas 2530u. P/U 186K, S/O 81K,
ROT 122K. Slide for 4/100' build/turn. Jet flowline as needed. BR full stands. Obtain final survey. BROOH and rack back 2 stands to 7965'. Pump high vis sweep
(on time, no increase) and circulate bottoms up x 3 at 525 gpm, 1850 psi, 80 rpms 18Kftlbs. Max gas 3077U, ECD 10.03 ppg. Rack stand back every bottoms up
to 7770'. Monitor well, observe gas break out but fluid level falling. RIH from 7770' to TD 8050, washing last 20' down at 525 gpm, 1840 psi, 30 rpms, 13.5Kft-lbs.
No fill. BROOH from 8050' to 7520' at 525 gpm, 1840 psi, 80 rpms, 18Kft-lbs, ECD 10.07 with 9.5 ppg mud. max gas 2359u. P/U 181K, S/O 86K, ROTW 122K.
Distance to WP3 (projected to TD): 4.63', 4.52' high, 1.02' right. Daily fluid lost to formation 15 bbls, total 295 bbls.
8/1/2023 BROOH from 7520' to 4400' at full drilling rates pulling 25-40 fpm as hole dictates. 525 gpm, 1540 psi, 80 rpms, 18-12Kft-lbs, ECD 10.37 with 9.5 ppg mud. max
gas 1789u. P/U 144K, S/O 75K, ROT 98K. BROOH from 4400' to 2945' at full drilling rates pulling 5-30 fpm as hole dictates. 380-525 gpm, 1400-2000 psi, 80
rpms, 7-12Kft-lbs, ECD 10.25 with 9.5 ppg mud. max gas 1935u. P/U 121K, S/O 71K, ROT 105K. 5-7 bph dynamic loss rate. Pull tight @ 2945' MD, top of SV3
(~2966' MD).Packoff @ 1900 psi (1400 psi clean) w/ 9.7k tq (1500 ft/lb over clean). Returns 50%. S/O, Slow pump rate and re-establsih full returns @ 380 gpm,
960 psi,80 rpm, 7.2k tq. Lost 25 bbls total during trouble interval. CBU 1x, 3514u @ btms up. 682 bgg. Continue BROOH from 2945' to 2681' at full drilling rates
pulling 5-30 fpm as hole dictates. 525 gpm, 1340 psi, 80 rpms, 7.2Kft-lbs, ECD 10.25 with 9.5 ppg mud. max gas 2789u. P/U 121K, S/O 71K, ROT 105K. 5-7
bph dynamic loss rate. Cont BROOH F/ 2,681' to 811' MD. 5-20 fpm as hole dictates. 525-400 gpm 660 psi 80-40 rpm Trq 8-4k MW 9.65, ECD 10.3, Max Gas
2781u. P/U 74k SLK 62k ROT 72k. At 2,282' MD Reduced to 475 gpm & 60 rpm, at 1,541' MD reduced to 450 gpm & 40 rpm. Dynamic losses 15-20 bph. At
811' MD Encountered Trq stall W/ 14k (2-3k clean) and over pull to 125k W/ no packing off, increased stall to 18k, worked string down to block weight and was
able to slack off. Reamed down to 843' MD W/O issue. Reamed back up to 811' MD stalled out at 18k W/ 155k over pull, no packing off. 400 gpm 630 psi
working string F/ 110k down to block weight (35k) numerus times. Released 18k Trq and made several attempts working up to 110k and string WT to 20k, no
success. Increased Trq stall to 22k working string. and firing jars (1X) in upstroke with no success. Reduced flow rate to 1 bpm 40 psi and oscillate W/ 20k string
weight W/ 2-5k Trq W/O success. Increased rate to 2 bpm 40 psi and increased Trq stall to 24k P/U to 120k and fired jars, no success. Re set jars and pulled to
150k and fired jars, free. Cont BROOH F/ 811' to 713' MD. 400-350 gpm 480 psi 30 rpm Trq 2-5k MW 9.65 ECD 10.01, Max Gas 30u. P/U 75k SLK 61 ROT 67k
Pull speed 1-10 as hole dictates. F/ 732' to 729' MD encountered trq stalls, Increased Trq stall to 8k and work through area. Dynamic losses 10-20 bph. Monitor
well 10 min, static. Attempted to pull on elevators observed 15 over pull. Cont BROOH F/ 713' to 442' MD. Rack 8 stands 5" HWDP and jar stand. 350 gpm 480
psi 30 rpm Trq 6-8k W/ occasional 10k Trq stall. P/U 62k SLK 54k ROT 61k. Trq drop F/ 6-7k to 2-3k at 508' MD. Pull speed 2-8 fpm. Able to pull on elevators F/
442' MD. L/D remaining 5" HWDP, X/O, 2 ea NM FC. Down load MWD. Daily disposal to G&I: 456 bbls total 4952. Daily disposal to MPU: 171 bbl total 877 bbls.
Daily H2O Lake 2" 980 bbls total 6440 bbls. Daily Lost DH: 200 bbls Total 495 bbls.
8/2/2023 Finish download MWD. L/D TM, M5,DM, GWD LWD/MWD tools. Drain mtr and B/O bit. L/D same. Bit grade PDC: 3,4,BT,A,CT,TD - TRI: 2,2,WT,A,F,2,LT,TD.
Clean and clear rig floor. Demob BHA components from rig floor and pipeshed. P/U 44k, S/O 44k. Grease crown and block sheaves. Svc, TDS, Spinners, FH-80,
wash pipe and drawworks. Remove inspection plates on flowline and clean flowline. Re-install inspection plates. PJSM, Mobilize Parker Casing equipment to rig
floor. R/D DP handling equipment. R/U Volant CRT, 9-5/8" side door (250T), Spot job box, Size safety clamp and slips. 72 BS cent staged on floor. Verify pipe
count. Flashlight float joints (good). Run 9-5/8" 40# TXP, L-80 csg as per detail. M/U Shoe track and check floats (good). Pump thru same @ 4 bpm (good). Install
bypass baffle "Top Hat" above float collar. M/U BFL collar. Baker lok all jts and tq to ~13.5k base of diamond. Cont RIH T/ 412' MD. 20.9k tq on connections. P/U
44k, S/O 44k. RIH with 9-5/8" 40# TXP, L-80 csg as per detail F/ 412' - T/ tag depth 1160' MD. 20.9k tq on connection. Fill every 5, break circ every 10th jt.
Began washing and reaming dn F/ 1160' to 1402' MD 2-8 bpm, 5-22 rpm, 12k max tq, 676u max gas. Observed mostly fine sand back at shakers while working
casing down thru upper build section. Numerous set downs and stalls starting from 1160' MD. Dynamic losses 20 BPH. Cont RIH 9.625" 40# L-80 TXP F/ 1,402'
to 2,xx' MD. Cont reaming down 5 bpm 60 psi 8-15 rpm Trq 4-12k (Stall set 12k) Max Gas 206u. Cont seeing stalls and set downs to 1,550' MD. Interment stalls
and set downs F/ 1,550' to 1,775' MD. Dynamic losses ~10 bph. Added 1 drum Lube 776 at 1,425' MD. Cont RIH F/ 1,775' MD W/ elevators minor set down and
washing down, run speed 40-60 fpm. Pump DS volume at BPF (2,282') F/ 2,314' to 2,438' MD 5 bpm 100 psi F/O 40% Max Gas 93u. Trq TXP 40# 20,960 ft/lb.
Fill every 5 jnts, top off 10. Clac 30 bbls Act -14 bbls Lost 44 bbls. Cont RIH 9.625" 40# L-80 TXP BTC Csg F/ 2,438' to 5,243' MD. Cont to wash or ream random
tight spots W/ 3 bpm 283 psi 5-15 rpm Trq stall 12k. Run speed 40-50 fpm. Fill every 5 jnts top off 10. Trq TXP 20,960 ft/lb. P/U 200k SLK 86k Calc 42 bbls Act
23.5 bbls Lost 18.5 bbls. Daily disposal to G&I: 399 bbls total 5351. Daily disposal to MPU: 57 bbl total 934 bbls. Daily H2O Lake 2: 350 bbls total 6790 bbls.
Daily Lost DH: 100 bbls Total 595 bbls.
8/3/2023 Cont RIH 9.625" 40# L-80 TXP BTC Csg F/ 5243' - T/ 5652' MD. M/U ES cmtr w/ Bakerlok (6 pins). Wash and Ream as needed (minor) 3 bpm 283 psi 5-15 rpm
Trq stall 12k. Run speed 40-50 fpm. Fill every 5 jnts top off 10. Trq TXP 20,960 ft/lb. P/U 225k S/O 76k. 47# csg above ES tool. Circulate and condition mud Rot /
Recip @ 5652' MD pumping 1x string volume. Stage up to 7 bpm, 215 psi, 26% flow. 14k tq, 12k tq, 2-5 rpm while reciprocating. 2002u Max gas. P/U 213k, S/O
102k. Cont RIH 9.625" 47# L-80 TXP BTC Csg F/ 5652' - T/ 7509' MD. Fill every 5 jnts top off 10. Trq TXP 23,830 ft/lb. P/U 307k S/O 87k. Cont RIH 9.625" 47#
L-80 TXP BTC Csg F/ 7509' - T/ tag depth 8050' MD w/ 10k set down. L/D tag jt #195 putting final casing set depth 8040' MD. Verify pipe count (good). Fill every
5 jnts top off 10. Trq TXP 23,830 ft/lb. P/U 290k S/O 90k Wash down last 2 jts 3 bpm, 500 psi ICP. Circulate and condition mud Rot / Recip on depth @ 8040'
MD. Stage up 3-7 bpm, 500 ICP, 220 FCP, 35% flow, 14k tq, 1-2 rpm, Break over 353k w/ 290k clean up wt, 90k dn. Full returns. 246u max gas. Pre treat mud
and prep pits for cement job. Rig up HES cementers. Shut dn and lineup on cmt line. PJSM, Wet lines w/ 5 bbls H2O (HES) and P/T low kick out 1,050/ 4,103 psi
high. Pump 1st stage cement job as follows: HES pump 60 bbls 10 ppg Tuned spacer w/ 4# red dye & 5 ppb poly flake (1st 10 bbls) 3.2 bpm 169 psi. Release F/
Volant & drop bypass plug. HES pump Lead EconoCem Type I/II. (Wet at 18:55) cmt 334 bbls (800 sx) 12 ppg, 2.347 yld, 5.5 bpm, ICP 490 psi FCP 503 PSI.
Tail HalCem Type I/II cmt 82 bbls (400 sx) 15.8 ppg, 1.155 yld, 3.5 bpm, ICP 476 psi FCP 559 PSI. Release F/ Volant & drop shutoff plug. Displace w/ 20 bbls
H2O (HES) 6.9 bpm 328 PSI then turn over to rig. Rig disp w/ 384 bbls 9.7 ppg spud mud, 7 bpm ICP 340 psi slowing to 6 bpm at 330 bbls away FCP 510 psi.
HES disp 80 bbls 9.4 ppg tuned spacer, 4 bpm ICP 404 psi FCP 511 psi. Stop Rot/Rec 1 rpm Trq 14k P/U 318k SLK 111k. Rig disp 115 bbls 9.7 ppg spud mud
3 bpm, ICP 786 psi FCP 786 psi. Bump plug. (Calc 573.8 bbls Act 579 bbls) Press up to 1,265 psi. Held pressure for 5 minutes, check floats - good. CIP 22:45
hrs. Lost 9 bbls. Max Gas 451u. Pumped at 3.5 bpm Press up to 2,852 psi to open ES Cementer. Cont pumping at 6 bpm 455 psi. No losses. On 2nd BU started
dumping 113 bbls clabber, 60 bbls spacer & ~104 bbls cement, 71 bbls black water Total 348 bbls. Adjusting pump rate 2-4.5 bpm to control packing off flow
line. Cont Circ at 4-6 bpm 485 psi dumping clabber as needed. Total 6 BU. Shut down pumps. Disconnect knife valve. Drain stack and rinse W/ Black H2O.
Function Annular 3X & drain stack. Clean out under shakers. Connect knife valve and clean cellar. Stage pumps up to 6 bpm 470 psi adjust flow rate as needed
for clabber at surface. Increase flow rates to 8 bpm xxx psi for 5 min every hour to clear out channeling. Prep pits and trucks for 2nd stage cement. Build more
Black H2O and high vis sweep. No losses. Daily disposal to G&I: 347 bbls total 5698 bbls. Daily disposal to MPU: 438 bbl total 1372 bbls. Daily H2O Lake 2: 810
bbls total 7600 bbls. Daily Lost DH: 65 bbls Total 660 bbls.
8/4/2023 Continue circ and condition mud via ES cmtr @ 2449' MD, 6 bpm, 470 psi. Surge rate to 8 bpm w/ 5 min hold every hour to help mitigate channeling. Pump 25
bbl hi vis sweep at end of cleanup cycle with no change in returns. L/D mousehole. 2nd stage cement job as per detail: flood lines with 5 bbls water at 5 bpm, 250
psi. Pump 60 bbls 10 ppg tuned spacer (with 4# red dye, 5# polyflake in first 10 bbls) at 3.5 bpm, 305 psi. pump 442 bbls (870 sxs) 10.7 ppg ArcticCem lead
cement at 5.5 bpm, 545 psi. Saw spacer and contaminated mud @ 360 bbls into total pumped. Good lead cement @ 480 total bbls pumped. Pump 56 bbls Type
I/II 15.8 ppg tail cement at 3.1 bpm, 315 psi. Drop closing plug. HES displace with 20 bbls water at 5 bpm, 250 psi. Swap to rig pumps and bump plug with 159
bbls (159 calculated) of 9.6 ppg spud mud, slow rate to 3 bpm last 10 bbls. 460 FCP. Pressure up and observe tool shift close at 1480 psi. Hold 2000 psi for 3
minutes. Bleed back 2 bbls to static indicated tool shifted close. CIP at 11:16. No losses. 248 bbls cement to surface. Full returns during job. PJSM Flush surface
equipment. Drain / Lift stack. N/D diverter line. Set "E" slips w/ 45k string wt. Cut 9.625" Csg - Vault rep (Josh Sandua) Cutoff jt - 28.62'. Set dn stack, johnny
whack W/ black H2O. C/O 9.625" elevators to 5" hydraulic. PJSM Lift and drain stack. Prep for Vault rep cutting 9.625" Csg. Vault rep (Josh Sandua) rough cut
9.625" Csg (28.62') Set down stack and johnny whack W/ black H2O. C/O 9.625" elevators to 5" hydraulic elevators. Secure Sack. Remove bell guide flange.
Install RCD head. Vault rep dress 9.625" Csg stump. Install FMC Gen 5 Multi Bowl Well Head. Trq RCMS flange 400 ft/lb & slip loc to 200 ft/lb. Test 500/ 3800
psi 10 min, good. Set test plug. Install 11" X 13 3/8" DSA. SIMOPS: Stage on rig floor, wear ring, MPD trip nipple, 4" TIW, 5" Dart and test tools. Cont cleaning
pits and inspect MP #2. PJSM N/U BOP on DSA. Start torque flange and installing chain binders. PJSM Trq BOP flange studs. Trq RCD head. Install choke, kill
lines, drip pan and install drain hoses. R/U 4" MPD hard lines. Install Koomey lines. Obtain RKB. Install short mouse hole. SIMOPS Inspect MP #1 and cleaning
pits. PJSM Flush through manual choke and kill. Flood stake and choke manifold. P/U 4.5" test jnt, M/U pump in sub, 5" TIW & 5" Dart. Work air out of choke
manifold. Perform shell test to 3,000 psi, good. Daily disposal to G&I: 1060 bbls total 6758 bbls. Daily disposal to MPU: 1201 bbl total 2573 bbls. Daily H2O Lake
2: 920 bbls total 8520 bbls. Daily Lost DH: 0 bbls Total 660 bbls.
8/5/2023 Test BOPs. Test 13-5/8" 5k Class V BOP equipment 250/3000 psi w/ 5 min hold on each. Chart and record same. Test annular w/ 4-1/2" TJ to 3k (good). Failed
initial test on upper VBRs. Change out upper rams and retest with no issue. Test 2x 5" TIW, 1x 4" TIW, 1x 5" dart. Test CMV 1-15. Test both HCR's, 2x manuals,
mezz kill, upper and lower IBOPs. Test with 4-1/2", 5" and 7" test jts. Witness by AOGCC rep Brian Bixby. Test alarms 10/20 ppg H2S, 20/40% LEL. Test PVT.
Drawdown - 3000 psi, drawdown 1500 psi, 200 psi increase28 sec, full charge 108 secs. 6 bottle avg N2O 2242 avg. R/D test equipment. B/D same. Install 9" ID
wear bushing and RILDS. PJSM Stage BHA tools on rig floor and pipe shed. R/U rig tongs. PJSM P/U M/U 8.5" RSS BHA. M/U 8.5" TK66 PDC Bit (6X13,
0.7777), 8.5" NRP, 7600 Geo Pilot, 6.75" ADR, 8.25" ILS, 6.75" DGR, 6.75" PWD, 6.75" DM, 6.75" ALD, 6.75" CTN, 6.75" TM Collars, Read MWD tools as per
MWD. Cont P/U 8.375" Integral Blade, 6.75" F.S (Non Ported, Plunger) , 6.75" NM FC,. 6.75" FS (Non Ported, Plunger) & 6.75" NM FC. RIH 2 stands 5" HWDP.
Pulse test MWD, good. POOH L/D 2 stands 5" HWDP. P/U to ALD and install nuclear sources. Cont P/U 5" HWDP & Jars to 431.91' MD. PJSM Single in hole
BHA #2 W/ 5" 19.5# S-135 NC50 D.P. F/ 432' to 2,413' MD. P/U 94k SLK 54k Drift (3.125" OD) D.P. F/ skate. Taking returns down drag chain. PJSM Wash
down F/ 2,413' to 2,448' MD tag closing plug. Drill F/ 2,448' to 2,462' MD. ES on depth (2,449' MD) 400 gpm 785 psi 40 rpm Trq 5-7k WOB 2-5k F/O 41%.
Observed rubber at shakers. Ream through ES 2X and trip though 2X W/O rotary, no issue. PJSM Cont single in hole F/ 2,462' to 2,546' MD. Encountered debris
taking 10-15k. Stared washing down. P/U 96k SLK 63k Drift (3.125" OD) D.P. F/ skate. Taking returns down drag chain. PJSM Single in hole W/ 5" 19.5# S-135
NC50 D.P. F/ 2,545' to 4,561' MD. P/U 137k SLK 71k Drift (3.125" OD) D.P. F/ skate. Taking returns down drag chain. Wash down chase debris & clabber F/
2,545' to 2,717' MD 400 gpm 820 psi 35 rpm Trq 4.2k. Cont RIH F/ derrick W/ 5" 19.5# S-135 NC50 D.P. F/ 4,561' to 7,746' MD. P/U 205k SLK 61k Drift
(3.125" OD) D.P. F/ skate. Taking returns down drag chain. Fill pipe every 2,500'. Wash down F/ 7,746' to 7,897' MD 400 gpm 1,340 psi. CBU 1.5X Attempted to
Rot/Rec stalling out at 13.5k and heavy drag. Parked at 7897' MD. Dumping clabbered mud as needed. 400-450 gpm 1,090-1,350 psi 1-5 rpm Trq 5-12.5k. P/U
215k SLK 78k. PJSM Pump through kill and choke line. Flood choke manifold and purge air. Test 9.625" Csg for 30 min. Pressure up to 2,677 psi 1st 15 min 27
psi, 2nd 15 min 13 psi Final 2,627 psi, good. Pumped 4.8 bbls bled 4.8 bbls. Daily disposal to G&I: 228 bbls total 6986 bbls. Daily disposal to MPU: 0 bbl total
2573 bbls. Daily H2O Lake 2: 280 bbls total 8800 bbls. Daily Lost DH: 0 bbls total 0 bbls. Surface loss 660 bbls.
8/6/2023 Flush through choke. R/D test Equip and align for well control. PJSM Drill cement and shoe track F/ 7,897' to 7,956' MD. Tag and drill BFA (7916') & FC (7957')
on depth. Work through 2X W/ ROT & 2X W/O. 400 gpm 1140 psi 40 rpm Trq 17-21k WOB 2-8k. Drill F/ 7,956 to 8,050' MD Tag Shoe on depth 450 gpm 1640
psi 80 rpm Trq 18-21k WOB 8k P/U 197k SLK 81k ROT 116k. Cont drilling 20' new hole F/ 8,050' to 8,070' MD 350 gpm 980 psi 80 rpm Trq 19-20k WOB 3-5k
F/O 38% P/U 197k SLK 81k ROT 118k. PJSM Displace Spud Mud to 9.2 ppg BaraDril N. Rot/Rec F/ 8,070' to 8,045' MD. 350 gpm 780 psi 80 rpm Trq 17-18k
ECD 9.59. P/U 190k SLK 85k ROT 118k. Obtain SPR's. Monitor well 10 min. PJSM Flood choke, kill & choke manifold. Shut UPR's. Perform FIT 12 EWM (712
psi) Pumped 1.6 bbls bled 1.6 bbls. B/D R/D. PJSM Break grey clamps. Pull trip nipple. Install RCD bearing on D.P. and set in RCD head. Tighten grey camps,
Install bowl saver. Flood MPD hard lines and test to 250/1250 psi, good. PJSM Cut & slip drilling line. (56') 9 wraps, 726 TM, ACCUMTM 746. Left on spool
3,744'. Circ at 400 gpm 900 psi shearing out mud while cut & slip. Calibrate blocks, check crown and floor saver. PJSM Service rig. Grease crown, TD, blocks &
spinners. Perform block sheave wobble EAM. Check oil in TD & rotary table. TIH F/ 7,950' to 8,070'. Drill 8.5" Hole F/ 8,070' to 8,780' MD (4,880' TVD) Total 710'
(AROP 118.3') 500 gpm/ mpd 499, 1,550 psi on, 1,455 psi off, 120 rpm, TRQ on 16-17k, TRQ off 15-16k, wob 5-10k. ECD 10.39, MW in/out 9.25/9.4, Max Gas
2105u. P/U 185k, SLK 78k, ROT 116k. MPD 100% open. Fault #1 8,512' MD throw 8' DTS F/ OBc to OBc. Drill 8.5" Hole F/ 8,780' to 9,583' MD (4,858' TVD)
Total 803' (AROP 133.8') 525 gpm/ mpd 525, 1,790 psi on, 1,780 psi off, 120 rpm, TRQ on 13-17k, TRQ off 12-14k, wob 6-12k. ECD 10.59, MW in/out 9.25/9.4,
Max Gas 2572u. P/U 165k, SLK 77k, ROT 114k. MPD 100% open. Back ream 60'. At 9,138' MD Survey Depth of 9,069' we dropped to 87.64 deg inc 2.79 deg
Azi in anticipation of sidetrack point. KOP at 9,138'MD building 3.5/100' and put a slight turn to the left to aid in sidetrack. Plan to sidetrack between 9,108' to
9128' MD. Distance to WP03: 10.30', 6.1' high 10' right. Fault #1 8,512' MD 6' throw 8' DTS. 11 concretions for a total thickness of 32' (2.2% of the lateral).
Footage Obc Sand 1,398'. Daily disposal to G&I: 1125 bbls total 8111 bbls. Daily disposal to MPU: 342 bbl total 2915 bbls. Daily H2O Lake 2: 700 bbls total 9500
bbls. Daily Lost DH: 0 bbls total 0 bbls. Surface loss 660 bbls.
8/7/2023 Drill 8.5" Hole F/ 9,583' to 9,655' MD (4,488' TVD) Total 72' (AROP 144') 525 gpm/ mpd 527, 1,820 psi on, 1,785 psi off, 120 rpm, TRQ on 13-16k, TRQ off 13-
15k, wob 6-13k. ECD 10.59, MW in/out 9.25/9.3, Max Gas 2345u. P/U 166k, SLK 72k, ROT 114k. MPD 100% open. Back ream 60'. Cont 3.5 deg/100 build.
Service rig. Grease spinners & PH8. Replace 4 bolts on Shaker #2. C/O 2 screens on Shaker #2,. Rot/Rec F/ 9,652' to 9,622' MD 210 gpm/mpd 211, 458 psi 80
rpm Trq 10k ECD 10.1 P/U 166k SLK 72k ROT 114k. Drill 8.5" Hole F/ 9,655' to PB1 TD 10,065' MD (4,722' TVD) Total 410' (AROP 103') 525 gpm/ mpd 527,
1,870 psi on, 1,820 psi off, 120 rpm, TRQ on 13-16k, TRQ off 13-15k, wob 8-15k. ECD 10.63, MW in/out 9.25/9.3, Max Gas 2335u. P/U 155k, SLK 76k, ROT
108k. MPD 100% open. Back ream 60'. Obtain final survey 9,993' MD 4,746.6' TVD 110.01 deg inc 1.16 deg azi. POOH on elevators as per MPD trip schedule
holding 200 psi static at 40 fpm F/ 10,065' to 9,140' MD. P/U 156k SLK 68k. No losses. Begin sidetrack operations F/ 9,140' to 9,158' MD trough at 60 fph W/
100% deflection. Drilling F/ 9,158' to 9,170' MD W/ 20 fph rop. F/ 9,170' to 9,267' MD increased to 50 fpm observing ABI dropping as per plan. POOH to 9,128'
MD and RIH to 9,267' MD. Check shot survey showed 87.58 deg inc W/ 90.86. deg inc from PB, good separation. 450 gpm/ mpd 450, 1,405 psi 120 rpm Trq
12.5-13k WOB 1-2k ECD 10.32, MW in/out 9.25/ 9.35. Max Gas 564u P/U 155k SLK 90k ROT 113k. Drill 8.5" Hole F/ 9,267' to 9,585' MD (4,887' TVD) Total
318' (AROP 127.2') 525 gpm/ mpd 525, 1,800 psi on, 1,780 psi off, 120 rpm, TRQ on 13-15k, TRQ off 13-14k, wob 10-15k. ECD 10.49, MW in/out 9.2/9.3, Max
Gas 2388u. P/U 155k, SLK 84k, ROT 105k. MPD 100% open. Back ream 60'. Drill 8.5" Hole F/ 9,585' to 10,108' MD (4,913' TVD) Total 523' (AROP 149.4') 525
gpm/ mpd 525, 1,930 psi on, 1,880 psi off, 120 rpm, TRQ on 12-13k, TRQ off 11-12k, wob 10-15k. ECD 10.7, MW in/out 9.25/9.35, Max Gas 2426u. P/U 153k,
SLK 83k, ROT 114k. MPD 100% open. Back ream 60'. Shaker #2 tripped breaker. Attempted to reset numerous times. Called out electrician and trouble shoot.
Appeared to be motor but upon further investigation supply wire shorted out. Went to D Pad to find correct gauge wire. Repaired wiring. Rot/Rec 10,092' to
10,029' 210 gpm/ mpd 210, 465 psi. 30 rpm Trq 9k P/U 148k SLK 95k ROT 120k Max Gas 2307u. Drill 8.5" Hole F/ 10,108' to 10,609' MD (4,870' TVD) Total
501' (AROP 83.50') 525 gpm/ mpd 525, 1,960 psi on, 1,890 psi off, 120 rpm, TRQ on 12-14k, TRQ off 11-12k, wob 7-15k. ECD 10.81, MW in/out 9.2/9.3, Max
Gas 3062u. P/U 152k, SLK 80k, ROT 110k. MPD 100% open. Back ream 60'. Fault #2 at 10,287' MD Throw ~102' DTS confirm correlation as we drill further.
Distance to WP03: 25.6'', 28' Low 2.3' right. Fault #1 8,512' MD 6' throw 8' DTS. 29 concretions for a total thickness of 357 (3.9% of the lateral). Footage Obc
Sand 2,001'. Out of zone 471'. PB1 10,065' to 9,158' MD. Daily disposal to G&I: 456 bbls total 8567 bbls. Daily disposal to MPU: 0 bbl total 2915 bbls. Daily H2O
Lake 2: 700 bbls total 10200 bbls. Daily Lost DH: 0 bbls total 0 bbls. Surface loss 660 bbls.
8/8/2023 Drill 8.5" Hole F/ 10609' - T/ 11236' MD (4848' TVD) Total 627' (AROP 105') 525 gpm/ mpd 525, 2000 psi on, 1825 psi off, 120 rpm, TRQ on 17-19k, TRQ off 16-
18k, WOB 8-16k. ECD 10.92, MW in/out 9.2/9.3, Max Gas 3023u. P/U 152k, S/O 71k, ROT 108k. MPD 100% open. Back ream 60'. Drill 8.5" Hole F/ 11236' - T/
11920' MD (TD depth)(4866' TVD) Total 684' (AROP 171') 525 gpm/ mpd 520, 2125 psi on, 2100 psi off, 120 rpm, TRQ on 17.9k, TRQ off 17k, WOB 8-16k.
ECD 11.01, MW in/out 9.2/9.3, Max Gas 2730u. P/U 150k, S/O 80k, ROT 107k. MPD 100% open. Back ream 60'. Obtain final svy @ TD 89.5 dreg inc 2.33 deg
azi. SPR's. Pump Tandem sweeps 30 bbl 8.4 ppg 34 vis & 30 bbl 9.8 ppg 360 vis. Return on time W/ 5% increase. Rot/Rec F/ 11,920' to 11,865' MD 550 gpm/
mpd 550, 2,360 psi 120 rpm Trq 18.5k ECD 10.96, MW in/out 9.4/9.45, Max Gas 1,913u. P/U 150k SLK 80k ROT 107k. MPD 100% open. Haul off surface mud,
clean pits and stage trucks for displacement. Rot/Rec F/ 11,920' to 11,865' MD 550 gpm/ mpd 550, 2,260 psi 120 rpm Trq 18-19k ECD 11.1, MW in/out 9.4/9.45,
Max Gas 253u. P/U 153k SLK 78k ROT 108k. MPD 100% open. PJSM Displace 9.4 ppg Spud Mud to 9.1 ppg QuikDril N Lubricated Brine. Pump 3X 40 bbl
SAPP pills W/ 20 bbls in between. Rot/Rec F/ 11,920' to 11,865' MD 415 gpm/ mpd 405, 1,025 psi 90 rpm Trq 11-21k ECD 10.5, Max Gas 35u. P/U 153k SLK
78k ROT 108k. MPD 100% open. Dumped 983 bbls. No losses. Shut in MPD and monitor well 10 min, no Press build. SPR's. PJSM BROOH F/ 11,920' to
11,270' MD 500 gpm/ mpd 485, 1,750 psi 120 rpm Trq 13-14k ECD 10.05, Max Gas 81u. P/U 153k SLK 78k ROT 108k. MPD 100% open. Pull speed 20-35 fpm
as hole dictates. Dropped 2.4" Steele Drift at 11,920' MD. Lost 12 bbls. PJSM BROOH F/ 11,270' to 9,137' MD RIH F/ 9,137' to 9,250' MD and survey confirm in
mother bore. Cont BROOH F/ 9,250' to 8,440' MD. 500 gpm/ mpd 497, 1,430 psi 120 rpm Trq 13-14k ECD 9.91, Max Gas 590u. P/U 153k SLK 87k ROT 112k.
MPD 100% open. Pull speed 20-35 fpm as hole dictates. Lost 14 bbls. Distance to WP03: 9.27'', 2.37' Low 8.96' right. Fault #1 8,512' MD 6' throw 8' DTS. Fault
#2 10,330' MD 80' throw DTS. 33 concretions for a total thickness of 110' (2.8% of the lateral). Footage Obc Sand 2,941'. Out of zone 939'. PB1 10,065' to 9,158'
MD. Daily disposal to G&I: 2030 bbls total 10597 bbls. Daily disposal to MPU: 365 bbl total 3280 bbls. Daily H2O Lake 2: 420 bbls total 10620 bbls. Daily Lost
DH: 22 bbls total 22 bbls. Surface loss 660 bbls.
8/9/2023 Cont BROOH F/ 8,440' to 8,040' MD 500 gpm/ mpd 497, 1,390 psi 120 rpm Trq 13-14k ECD 9.91, Max Gas 493u. P/U 151k SLK 85k ROT 116k. MPD 100%
open. Pull speed 20-35 fpm as hole dictates. Pump 30 bbl 9.1 ppg 250 vis sweep, Back on time 10% increase. Rot/Rec F/ 8,040' to 7,995' MD 550 gpm/ mpd
540, 1,650 psi 80 rpm Trq 8k, Max Gas 103u. P/U 143k SLK 103k ROT 121k. Shut in MPD for 10 min, no build. Drain stack, pull bushing and back out grey
clamp. Pull RCD bearing to rig floor and strip off stand. Install trip nipple and tighten grey clamp. Pull 10 stands and check for swabbing, good. POOH on
elevators F/ 7,995' to 4,816' MD. P/U 133k SLK 93k. PJSM Cont to POOH L/D 5" D.P. F/ 4,816' to 431' MD Perform CAT IV inspection on D.P. P/U 57k SLK 57k
Lost 7.7 bbls. PJSM L/D BHA #2. L/D 5" HWDP & Jar. Unload nuclear source. Cont L/D CTN & ALD. Down load MWD. L/D remaining BHA components. Bit
Grade 1-3-BT-N-X-I-WT-TD. Static loss rate 1.4 bph. PJSM Stage 4.5" & 7" handling tools on rig floor. P/U R/U 9.625" Eckel HD power tongs. Prep shed for liner
run. PJSM P/U M/U shoe jnt and RIH 4.5" 12.6 # L-80 W563 liner as per tally to 3,985' MD. W563 Trq 3,700 ft/lb. P/U 65k SLK 56k. Run speed 60-80 fpm. Lost
7.4 bbls. PJSM R/D 4.5" handing Equip and R/U 7" Handling Equip. Cont RIH W 7" 26# L-80 W563 F/ 3,985' to 5172 MD. Trq W563 to 9,400 ft/lb. P/U 90k SLK
79k. PJSM R/D 7" elevators and install 5" Hydraulic Elevators. L/D thread protectors. PJSM P/U M/U SLZXP. M/U Shear out ball Assy (Set 4,100 psi) to 7" X
9.625" SLZXP Liner Top Packer. "DG" Slips 7ea 7/16" screws, Shear 6 ea 1/2" screws 1,800 psi, Neutralizer Press 10 ea 1/2" screws 2,710 psi, RIH to 5.268'
MD. M/U 1 stand 5" D.P. and pump through at 2 bpm 75 psi.P/U 90k SLK 79k. PJSM Convey liner W/ 5" D.P. out of derrick F/ 5,268' to 9,083'' MD. P/U 143k
SLK 94k. At 7,996' MD attempt to get rotating parameters, stalled at 3k Trq. Lost 1 bbl. Daily disposal to G&I: 57 bbls total 10654 bbls. Daily disposal to MPU: 0
bbl total 3280 bbls. Daily H2O Lake 2: 260 bbls total 10880 bbls. Daily Lost DH: 40 bbls total 62 bbls. Surface loss 660 bbls.
8/10/2023 Continue to convey 4.5" Liner on 5" DP from 9,083' to 11,920'. PUW 173K, SOW 96K, Wash last 2 stands to bottom @ 4 BPM, 400 PSI. Tag bottom on depth
w/10K, P/U, and Drop 1.125 Ball, M/U single and tag bottom, P/U to tension, Circ ball down at 4 bpm, slowing to 1.5 bpm, ball on seat at 1478 stks. PSI up to
2100 psi to Set SLZXP, hold 5 min,(Set @ 1700 PSI). Set 75K on PKR,. PSI up to 3000 hold for 5 min. Blow ball seat @ 3200 PSI. P/U to Free Travel WT (140K)
Lost 33K, TOL @ 6,726'. R/U to test and chart Liner Top, pump through Kill Line while blowing down Choke, Shut down, shut UPR's, flood through Choke, PSI
up to 1500 PSI, hold for 10 min on chart. Good, Bleed off and rig down test equipment. PSI up to 300 PSI, P/U on string until PSI dumped verifying out of Liner
Top. Rack Back stand #106. Monitor wellfor 10 min-static. Pump Corrosion inhibeted Dry Job. B/D Choke and Kill Lines and Top Drive. L/D 5' DP from 6700' to
4,228'. P/U 107, SO 86K. Lost 1.5 bbls. Continue to L/D 5' DP from 4,228' to the liner running tool. L/D Liner Running Tool. Lost 3 bbls. PJSM YoYo remaining 5"
D.P. F derrick and L/D. F/ 1,015' MD. Lost 4 bbls. Daily disposal to G&I: 0 bbls total 10654 bbls. Daily disposal to MPU: 0 bbl total 3280 bbls. Daily H2O Lake 2: 0
bbls total 10880 bbls. Daily Lost DH: 17 bbls total 79 bbls. Surface loss 660 bbls.
Activity Date Ops Summary
8/10/2023 PJSM M/U wear ring puller to 5" D.P. BOLDS and pull wear ring. L/D. PJSM P/U M/U 7" handling Equip. C/O hydraulic elevators to 7" 250T side door elevators.
R/U 9.625" Eckel power tongs. Prep pipe shed. PJSM Dummy run 7" landing jnt. P/U M/U Baker Seal Assy and W/ RIH 7" 26# L-80 BTC to 1,950' MD. P/U 68k
SLK 65k Run speed 50-60 fpm. TRQ BTC 6730 ft/lb. Lost 5 bbls. At 765' MD adjusted stack due collars contacting wellhead. PJSM Cont RIH W/ 7" 26# L-80 BTC
to F/ 1,950 to 5,438' MD. P/U 68k SLK 65k Run speed 30-50 fpm. P/U 127k SLK 99k. TRQ BTC 6730 ft/lb. Lost 7 bbls.
8/11/2023 Run 7" 26# BTC Casing F/5,438' - T/6,737' at 30-50fpm, Torqueing Connections T/6,730ft-lbs. Set Down 10K on No-Go using 2 additional joints from Shed (#163
and #164), observing seals drag 3k for entry. P/U=151K, S/O=113K. Calculated displacement=21 bbls, Actual=30bbls, Loss=9bbls. Laid down additional Joints
from Shed (#163 and #164) and Joint #162. P/U a 20.12', 3.83' Pups and Joint #162 along with the hanger and spaced out 1.62' off of No-Go. TOL = 6727.53'.
Mule Shoe depth at 6735.50'. Close Annular and increase pressure to 500psi on the OA - Strip up thru the annular observing the pressure dumped as per
calculated, exposing the 4-1" circulation ports. PT LRS to 2900psi. Reverse Circulate 121bbls of 9.1ppg CI brine (ICP=205psi, FCP=180psi) at 4BPM with Rig
Pumps. LRS chased CI Brine with 63bbls of FP Diesel (ICP=42psi, FCP=436psi) at 4BPM. Strip back down thru the annular seating the hanger without issue -
Land Hanger with 78K in wellhead, RILDS. Bleed off all pressure and open Annular. L/D Landing Joint along with 7" Elevators. R/U for 5" and M/U Pack-off
Running tool on 5" DP. Set pack off and test void to 5000psi for 10 mins per Wellhead. LRS PT Lines to 2900psi. Flood Lines and Test 9-5/8" x 7" OA to 1500 psi
for 30 mins (Charted) - Good (Starting Pressure=1729psi, 15min=1692psi, final=1678psi). Pumped 2.43bbls, bled back 2.1bbls. Parker TRS Load Rig Floor with
4.5" Handling Equipment (Torque Turn, Slips, Dog Collars and Elevators) for running Upper Completions. M/U Mule Shoe and RIH with 4.5" 12.6# L-80 JFE Bear
Tubing F/Surface - T/1,269' as per tally, Torque Turning Connections T/5,400ft-lbs. P/U=46K, S/O=45K. Calculated=4bbls, Actual=2bbls, Loss=2bbls. Comms
failure W/ Trq turn Equip unable to read Trq. Trouble shot. C/O load cell, cables and JBox. Tested Equip and was able to see Trq readings. Cont RIH with 4.5"
12.6# L-80 JFE Bear Tubing as per tally F/ 1,269' to 3,370' MD. Run speed 50-75 fpm. Torque Turning Connections T/5,400ft-lbs. P/U=62K, S/O=56K.
Calculated= 14 bbls, Actual= 8 bbls, Loss= 6 bbls. Cont RIH with 4.5" 12.6# L-80 JFE Bear Tubing as per tally F/ 3,370' to 7,597' MD. Run speed 75 fpm. Torque
Turning Connections T/5,400ft-lbs. P/U=96K, S/O=70K. Calculated= 20 bbls, Actual= 13 bbls, Loss= 7 bbls. Daily disposal to G&I: 471 bbls total 11125 bbls. Daily
disposal to MPU: 57 bbl total 3337 bbls. Daily H2O Lake 2: 0 bbls total 10880 bbls. Daily Lost DH: 22 bbls total 101 bbls. Surface loss 660 bbls.
8/12/2023 Continue to run 4.5" JFE Bear 12.6# L-80 Tubing F/7,597' - T/7,950', Torque turning connections to 5,400ft-lbs. Running Speed set at 75fpm. Make up hanger
landing joint and land hanger out. P/U=97K, S/O=70K, Weight hanging off of Hanger = 35K. Vault Rep RILDS, back out landing joint and install CTS-BPV. Remove
4.5" handling equipment from floor. P/U 5" handling equipment and R/U Stack Flushing tool, flush BOP Stack at 15BPM. Flush and blow down kill/choke lines. Prep
Cellar for R/D of BOPe. Drain stack and remove come-alongs. SIMOPS: Clean Pits. R/U Parker TRS and prep to pull Hanger back to floor. Upon further review it
was determined that the Production packer needed to be moved further down the hole out of the SLZXP. R/U Power tongs and Elevators. M/U Landing Joint, un-
seat hanger and pull hanger back up to the rig floor. P/U=98K to unseat. Bring Pup joints to floor. L/D Hanger and Jt #190. P/U a 9.66, 9.65 and 2.85' pup. M/U Jt
#190, Hanger and land WLEG at 7,972.60', L/D Landing Joint. SIMOPS: Continue to clean pits and process 5" DP in Shed. Nipple down BOPe. Remove Trip
Nipple and install MPD Test cap. Install bridge cranes. Remove Kill/Choke Lines and disconnect Koomey Lines. P/U Stack and rack back on pedestal. R/D DSA.
Continue SIMOPS. Wellhead Clean CTS-BPV profile, checking all seals. Install API Rings and set tree on Wellhead, torque to spec per Vault Rep. SIMOPS: Prep
Pits for Shaker removal. R/U test Equip. Test Hanger void 5 min 500 psi & 10 min 5,000 psi, good. Fill tree with H2O and test 5 in 500 psi & 10 min 5,000 psi, good.
R/D test Equip. SIMOPS prep shakers for removal. Clean Pits. Process 5" D.P. in pipe shed. PJSM R/U Circ manifold and HP lines on rig floor to Tubing and IA.
Line up to reverse Circ. R/U LRS and PT to 1,800 psi. SIMOPS Cont W/ shakers and pits. PJSM Reverse Circe, Rig pump 85 bbls 9.1 ppg corrosion inhibited brine
down IA 3 bpm ICP 250 psi FCP 195 psi. LRS pump 82 bbls FP Diesel (70 deg F) at 1.25 bpm ICP 200 psi FCP 400 psi. LRS vac back lines and R/D. Line up to U
Tube. SIMOPS Cont Pit operations. PJSM Blow down MP #1 & #2. Bridle up derrick for scoping down. Start rig move check list. Cont pit operation and D.P. Cont to
U Tube. Daily disposal to G&I: 466 bbls total 11591 bbls. Daily disposal to MPU: 0 bbl total 3337 bbls. Daily H2O Lake 2: 0 bbls total 10880 bbls. Daily Lost DH: 0
bbls total 101 bbls. Surface loss 660 bbls.
8/13/2023 PJSM Shut in tuning and IA. R/U test Equip. R/D HP tubing line on tree. P/U M/U ball & rod launcher. Load 1 7/8" Ball and roller rod. M/U to tubing and drop ball/
rod. L/D launcher. Trouble shut chart recorder, test lines and senators. Replace bad test line. PT lines to 3,500 psi, good. PJSM Press up to set TNT to 500 psi for 5
min, Cont to press up to 3,690 psi. Packer set at ~2,260 psi. Cont test 4.5" Tubing to 3,690 psi final 3,510 psi, initial 15 min 144 psi last 15 min 36 psi OA 150 psi.
Pumped 1.6 bbls, bled 1.5 bbls. Line up to 7" X 4.5" IA. Test to 3,640 psi initial 15 min 77 psi last 15 min 11 psi Tubing 550 psi. pumped 2.4 bbls bled 2.3 bbls.
R/D test Equip. Release rig 03:30.
50-029-23760-00-00API #:
Well Name:
Field:
County/State:
PBW Z-235
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
132
59
X Yes No X Yes No 4.7
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: 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:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes 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:
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:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
RKB
10
250 38155.6
SE
C
O
N
D
S
T
A
G
E
MP #1
11:16
Cement Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.7
Shoe @ 8042 FC @ Top of Liner7,956.25
Floats Held
30 498
248 250
Spud Mud
CASING RECORD
County State Alaska Supv.S Barber / O Amend
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW Z-235 Date Run 2-Aug-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC OSP 1.75 8,042.40 8,040.65
25.57 25.57
Csg Wt. On Hook:311 Type Float Collar:Baffle Adapter No. Hrs to Run:28.5
9.7 7
1480
10
10.7 442 5.5
99.9
786
Bump Plug?
FI
R
S
T
S
T
A
G
E
15.8
460
3.1
9.6 6 159/159
579/573.8
1265
104
MP #1
15.8 82
Bump press
ES Cementer
Bump Plug?
ok
22:45 8/3/2023 2,448
2448.82
8,042.008,050.00
CEMENTING REPORT
Csg Wt. On Slips:45,000
Spud Mud
Tuned Spacer 4# Red Dye/ 5# Pol E Flake
870 2.85
Stage Collar @
60
Bump press
100
248
ES Cementer Closure OK
56
12 334
26.30 RKB to CHF
Type of Shoe:Standard Casing Crew:Parker Wellbore
No. Jts. Delivered 205 No. Jts. Run 194 11
Length Measurements W/O
Threads
Ftg. Delivered 8,405.00 Ftg. Run 8,040.00 Ftg. Returned 365.00
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
ArcticCem Type I/II
Type
Jnt 1 2 ea BS & 4 ea SR 10' from end, 1 ea BS & 2 ea SR jnt 2 & 3. Solid Body Every jnt F/ 4-25, every other F/ jnt
27-73, 1 ea 132-135, 1 ea BS & 1ea SR ES pups, SB 1 ea jnt 136-139,every 3rd jnt F/142-190. Total 7 bow springs,
6 stop rings, 70 solid body.
9.625" Csg 9 5/8 40.0 L-80 BTC 82.56 8,040.65 7,958.09
FC 10 BTC OSP 1.39 7,958.09 7,956.70
9.625" Csg 9 5/8 40.0 L-80 BTC 39.12 7,956.70 7,917.58
Baffle Adapter 10 BTC Halliburton 1.39 7,917.58 7,916.19
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 5,446.95 7,916.19 2,469.24
Pup 9 5/8 40.0 L-80 BTC 17.60 2,469.24 2,451.64
ES Cementer 10 BTC Halliburton 2.82 2,451.64 2,448.82
Pup 9 5/8 40.0 L-80 BTC 18.07 2,448.82 2,430.75
9.625" Csg 9 5/8 40.0 L-80 TXP BTC 2,405.18 2,430.75 25.57
EconoCem Type I/II 800 2.35
HelCem Type I/II 400 1.16
5.5
HalCem Type I/II 270 1.17
8/4/2023 Surface
Spud Mud
1
Regg, James B (OGC)
From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent:Saturday, September 2, 2023 1:19 PM
To:Brooks, Phoebe L (OGC); Wallace, Chris D (OGC); Regg, James B (OGC)
Cc:PB Wells Integrity
Subject:Hilcorp (PBU) August 2023 MIT Forms
Attachments:Aug 2023.zip
All,
AƩached are the completed AOGCC MIT forms for the tests completed in August 2023 by Hilcorp North Slope, LLC.
Well: PTD: Notes:
X‐24A 1991250 2‐year MIT‐IA per AA AIO 3B.003. Failed and well was shut‐in.
Z‐234 2230650 Rig MIT‐T/MIT‐IA per PTD
Z‐235 2230550 Rig MIT‐T/MIT‐IA per PTD
Please respond with quesƟons or concerns.
Andy Ogg
Hilcorp Alaska LLC
Field Well Integrity
andrew.ogg@hilcorp.com
P: (907) 659‐5102
M: (307)399‐3816
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.
PBU Z-235PTD 2230550
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230550 Type Inj N Tubing 0 3690 3546 3510 Type Test P
Packer TVD 4544 BBL Pump 1.6 IA 0 150 150 150 Interval I
Test psi 3500 BBL Return 1.5 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230550 Type Inj N Tubing 0 550 550 550 Type Test P
Packer TVD 4544 BBL Pump 2.4 IA 0 3640 3563 3552 Interval I
Test psi 3500 BBL Return 2.3 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
Hilcorp North Slope LLC
Prudhoe Bay / PBU / Z-Pad
Waived by Guy Cook
James Lott
08/13/23
Notes:Rig MIT-T
Notes:
Notes:
Notes:
Z-235
Z-235
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:Rig MIT-IA
Notes:
Notes:
Form 10-426 (Revised 01/2017)2023-0813_MIT_PBU_Z-235_2tests
J. Regg; 10/12/2023
David Douglas Hilcorp North Slope, 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:
Hilcorp North Slope, LLC
Date: 08/31/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU Z-235
PTD: 223-055
API: 50-029-23760-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (07/27/2023 to 08/08/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU Z-235 LWD Subfolders:
PBU Z-235 Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-055
PBU Z-235: T37971
PBU Z-235 PB1: T37972
8/31/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.31
16:15:24 -08'00'
David Douglas Hilcorp North Slope, 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:
Hilcorp North Slope, LLC
WELL: PBU Z-235PB1
PTD: 223-055
API: 50-029-23760-70-00
FINAL LWD FORMATION EVALUATION LOGS (07/27/2023 to 08/07/2023)
x EWR-M5, AGR, ABG, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
PBU Z-235PB1 LWD Subfolders:
Please include current contact information if different from above.
8/31/2023
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN ORIN Z-235
JBR 09/28/2023
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:1
Tested with 4 1/2" and 7" Tets Joints, Tessted all PVT and gas alarms, UPR failed were changed out and passed retest. Total of
20 precharge bottles all at 1000psi each.
Test Results
TEST DATA
Rig Rep:S. BarberOperator:Hilcorp North Slope, LLC Operator Rep:J. Sture
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2230550 DATE:8/5/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopBDB230808065623
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6
MASP:
1662
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 2 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"P
#1 Rams 1 2 7/8"x 5 1/2"FP
#2 Rams 1 Blinds P
#3 Rams 1 7"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"P
HCR Valves 2 3 1/8"P
Kill Line Valves 1 3 1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1500
200 PSI Attained P28
Full Pressure Attained P104
Blind Switch Covers:PYES
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2242
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
0 NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P14
#1 Rams P9
#2 Rams P9
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9999
9
9
9
9FP
UPR failed
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil, PBU Z-235
Hilcorp Alaska, LLC
Permit to Drill Number: 223-055
Surface Location: 4433' FSL, 2642' FEL, Sec. 19, T11N, R12E, UM, AK
Bottomhole Location: 855' FNL, 2402' FWL, Sec. 17, T11N, R12E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of July 2023. 13
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.13
15:23:45 -05'00'
1a.
Contact Name:Joe Engel
Contact Email:jengel@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8395
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
5
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
5
Gas Hydrates
Geothermal
Hilcorp North Slope, LLC Bond No. 107205344
11.Well Name and Number:
PBU Z-235
TVD:11920'4869'
12. Field/Pool(s):
MD:
ADL 028262
85-009 July 15, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
4433' FSL, 2642' FEL, Sec. 19, T11N, R12E, UM, AK
408' FSL, 2253' FWL, Sec. 17, T11N, R12E, UM, AK
Kickoff Depth:300 feet
Maximum Hole Angle: 93 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:2151 1662
17.Deviated wells:16.
Surface: x-y- Zone -600034 5959240 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
82.6'
56.1'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
1996'
Surface
4629'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
Commission Use Only
See cover letter for other
requirements:
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
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
6930'5115'
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
855' FNL, 2402' FWL, Sec. 17, T11N, R12E, UM, AK
Time v. Depth Plot555 5Drilling Program
12536'
Stg 2 L - 2526 ft3 / T - 313 ft3
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8026#/12.6#7"x4-1/2"
9-5/8"
4629'
12-1/4"
6930'Uncemented Tieback
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
2480
610'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
Tieback
9-5/8" 47#
40#
26#
L-80
L-80
L-80 BTC
Vam 21
BTC
Hyd 563
2500'
5430'
6930'
Surface
2500'
Surface
2500'
7930'
11920'
1996'
4893'
4869'
Stg 1 L - 1802 ft3 / T - 457 ft3
Uncemented Slotted Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
105'105'Driven 20"X-52 80'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
PRUDHOE BAY FIELD /
SCHRADER BLUFF OIL POOL
ORION DEVELOPMENT AREA
6.22.2023
By Grace Christianson at 9:15 am, Jun 22, 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: 2023.06.22 08:57:03 -08'00'
Monty M
Myers
SFD 7/12/2023
1662
223-055
* BOPE pressure test o 3000 psi. Annular to 2500 psi.
* Variance to 20 AAC 25.412 (b) Approved for packer placement to
be greater than 200' from top of perforations. Packer to
be place within the reservoir to assure monitoring of IA for in-zone injection.
* State to witness MIT-T and MIT-IA to 3500 psi.
DSR-6/23/23MGR26JUN2023
50-029-23760-00-00
Service - WAG
GCW 07/13/2023
07/13/23
07/13/23
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.07.13 15:24:00 -05'00'
87
1718
20
CHEV181112
K071112PB1
W-26
W-44
WETW
Z-03
Z-06
8 Z-100
Z-102
Z-103
Z-108Z-112PB1
Z-113PB1
Z-114
Z-115
Z-116
Z-19A
Z-210
Z-210PB1
Z-34
-35PB1
-38
38PB1
Z-39
Z-50
Z-61
Z-65
Z-68
Z-69
Z-70
Z-71
Z-220PB1
Z-220
Z-228
Z-229
Z-222
Z-223
W-241
W-26B
Z-235_wp01
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
Z-235 Injector (Proposed)
FEET
05001,0001,500
POSTED WELL DATA
Well Label
WELL SYMBOLSINJ Well (Water Flood)
P&A Oil/Gas
J&A
Temporarily Abandoned
Active Oil
Injector Location
Shut in Injector
REMARKS
Well Symbols at top of Schrader Bluff OBc sand (targetof proposed Z-235 well). Black dashed circles and lines
= 1320' radius from heel to toe of proposed Z-235 lateralinjector.
By: KRE
March 22, 2023
PETRA 3/22/2023 4:24:16 PM
Well Name PTD API StatusTop of Oil Pool(SB OBc, MD)Top of Oil Pool(SB OBc, TVD)Top of Cmt (MD) Top of Cmt (TVD)ZonalIsolationCommentsZ-116 211-124 50-029-23455-00-00 WAG Injector 9852' 4860' 8640' 4323' Closed7" TOC logged at 8640' MDwith IBC on 12/22/2011.Kuparuk Injector, not open toSchrader BluffZ-228 222-055 50-029-23718-00-00 Producer 6727' 4797' Surface Surface Closed Active SB Producer. 9-5/8"cemented fully from shoe at7492' MD to surface in 12-1/4" hole. 2 stage cement job.14bbls excess seen from 1ststage, 185 bbls excess tosurface on second stage.Z-229 222-104 50-029-23726-00-00 Producer 7360' 4853' Surface Surface Open Active SB Producer. 9-5/8"cemented fully from shoe at7318' MD to surface in 12-1/4" hole. 2 stage cement job.30bbls excess seen from 1ststage, 330 bbls excess tosurface on second stage.W-26B 222-151 50-029-21964-02 Producer 8196' 4913' 6393' 4210' ClosedActive SB Producer 9-5/8"casing cemented in 2 stages.CAST-M showed first stageTOC at 6393' MD. CSG shoe at8727' MDW-241 222-154 50-029-23741-00 WAG Injector 7358' 4949' 6386' 4560' ClosedActive SB Injector 7" casingcemented with 47bbls of15.8ppg cement. Full returnsduring cement job. 7" shoe at7817' and estimated TOC at6386' MD based on 30%washoutPBU Z-210PB1 204-181 50-029-23226-70-00 Plugback 7370' 4844' 4810' 3499' Closed2004 USIT found 7" TOC @4810' MD.Area of Review PBU Z-235
Prudhoe Bay West
(PBU) Z-235
Drilling Program
Version 1
6/14/2023
Table of 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 13-5/8” 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 39
19.0 Innovation Rig Diverter Schematic ......................................................................................... 41
20.0 Innovation Rig BOP Schematic ............................................................................................... 42
21.0 Wellhead Schematic ................................................................................................................. 43
22.0 Days Vs Depth .......................................................................................................................... 44
23.0 Formation Tops & Information............................................................................................... 45
24.0 Anticipated Drilling Hazards .................................................................................................. 47
25.0 Innovation Rig Layout ............................................................................................................. 51
26.0 FIT Procedure .......................................................................................................................... 52
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
28.0 Casing Design ........................................................................................................................... 54
29.0 8-1/2” Hole Section MASP ....................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU Z-235
Pad Prudhoe Bay Z Pad
Planned Completion Type 4-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBc Sand
Planned Well TD, MD / TVD 11,920’ MD / 4,869’ TVD
PBTD, MD / TVD 11,910’ MD / 4,869’ TVD
Surface Location (Governmental) 4,433' FSL, 2,642' FEL, Sec 19, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 600,033.5, Y=5,959,240
Top of Productive Horizon
(Governmental)408' FSL, 2253' FWL, Sec 17, T11N, R12E, UM, AK
TPH Location (NAD 27) X= 604,906.5, Y=5,960,562
BHL (Governmental) 855' FNL, 2402' FWL, Sec 17, T11N, R12E, UM, AK
BHL (NAD 27) X= 604986, Y=5,964,579
AFE Number 231-00086
Maximum Anticipated Pressure
(Surface) 1662 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2151 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft +56.1ft =82.6ft
GL Elevation above MSL: 56.1 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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Z-235 SB Injector
Drilling Procedure
2.0 Management of Change Information
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Z-235 SB Injector
Drilling Procedure
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 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 BTC 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,254 5,410 604
8-1/2”7” 6.276 6.151 7.656 26 L-80 H563 7254 5410 604
4-1/2” 3.958 3.833 5.2 12.6 L-80
H563 7780 6350 267
Tubing 4-1/2” 3.958 3.833 5 12.6 L-80 JFE Bear 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
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.
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.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@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.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
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 jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Josh Stephens 907.777.8420 josh.stephens@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Natalie Brent 907.564.4313 nbrent@hilcorp.com
Drilling Env.
Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU Z-235 is a grassroots injector planned to be drilled in the Schrader Bluff OBc sand. Z-235 is part of a
multi well program targeting the Schrader Bluff sand on PBU Z-pad.
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set in the OBc. An 8-1/2” section will
be drilled in the OBc. A 4-1/2” slotted injection liner will be run in the open hole section, followed by a 7”
tieback, and the well will be completed with injection tubing. Z-235 will not be pre produced prior to
injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately July 15, 2023, pending rig schedule.
Surface casing will be run to 7,930’ MD / 4,893’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” hole to TD
6. Run 4-1/2” injection liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote Ops geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote Ops geologist. LWD: GR + ADR (For geo-steering)
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU Z-235. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 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 or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1) “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the surface casing shoe landing at the Obc
production interval at ~85 degrees inclination. In order to make the ball and rod we land to set the production
packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees inclination. The
MD we currently have planned for 70 degrees is at ~7260’ MD. The production packer will be ~50’ MD above
the X nipple which puts it at ~7050’ MD / ~4680’ TVD. The surface casing shoe is planned at ~7930’ MD / 4893’
TVD which means the planned packer depth is ~880’ MD away. From a TVD standpoint, the production tubing
packer is ~213’ TVD from the surface casing shoe. With the surface casing set in the Schrader Bluff sand, and the
injection packer set inside the surface casing, injection fluids will be confined to the Schrader bluff sands.
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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)
MIT-IA to 3500 psi after landing production tubing. - mgr
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Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 Z-235 will utilize a prior set 20” conductor on Z-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
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Z-235 SB Injector
Drilling Procedure
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
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.
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Z-235 SB Injector
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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Z-235 SB Injector
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
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 Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the OBc Sand. Confirm this setting depth with the
Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk and offset any gas cut MW, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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Z-235 SB Injector
Drilling Procedure
x Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’
TVD (Base of Perm) to 2740’ TVD (Top Ugnu). Be prepared for hydrates:
x Gas Hydrates are present on Z PAD
x Keep mud temperature as cool as possible, Target 60-70*F
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
x Drill through hydrate sands and quickly as possible, do not backream.
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid 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 and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x PVT System: 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.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
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Z-235 SB Injector
Drilling Procedure
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity. Drop mud temp as low as possible as well.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
x Ensure mud temp is as low as possible when backreaming before and through the SV 2 & 3
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50, and VAM 21 x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
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 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
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Drilling Procedure
12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,500’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD).
x Confirm depth of first major hydrates seen (possibly SV3) and position stage tool above if
possible, confirm with geo and drilling engineer before adjusting depth and ensure there is
enough 1st stage cement available
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 47# L-80 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8” 40# L-80 BTC MUT:
Casing OD Minimum Optimum Maximum
9-5/8”29,800 ft-lbs -34,800 ft-lbs
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Drilling Procedure
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Drilling Procedure
12.8 Continue running 9-5/8” surface casing
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Drilling Procedure
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement 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 cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (7,930'-1,000'-2,500') x 0.0558 bpf x 1.3 321.2 1802.2
Total Lead 321.2 1802.2 766.9
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0
Total Tail 81.6 457.8 394.7LeadTail
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.12 Displacement calculation:
2500’ x 0.0732 bpf + (7,930’-120’-2500’) x .0758 bpf =
= 585.6 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.15 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.16 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
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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Drilling Procedure
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.17 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.18 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Drilling Procedure
Second Stage Surface Cement Job:
13.19 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
a. Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.21 Fill surface lines with water and pressure test.
13.22 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.23 Mix and pump cmt per below recipe for the 2
nd stage.
13.24 Cement volume based on annular volume + open hole excess (300% for lead based on past Z pad
surface cement jobs and 100% for tail). Job will consist of lead & tail, TOC brought to surface.
However cement will continue to be pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 4 421.7 2365.8
Total Lead 450.3 2526.2 886.4
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6LeadTail
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.85 ft3/sk 1.17 ft3/sk
Mixed
Water 14.6 gal/sk 5.08 gal/sk
x 4
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Drilling Procedure
13.27 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.28 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.29 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.30 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.31 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
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 jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 3-1/2” test joint
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.5 ppg Baradrill-N fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” directional BHA
x Motor and Triple Combo
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. 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 Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a solid float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.2 TIH w/ 8-1/2” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.8 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
g
Submitpp(
casing test and FIT digital data to AOGCC.
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Drilling Procedure
15.8 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco 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.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total Solids MBT HPH
T
Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
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Drilling Procedure
15.9 Install MPD RCD
15.10 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid
15.11 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Reservior plan is to cross all lobes of the Schrader Bluff sand and TD beneath the OBC.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Hole Section A/C:
x Z-234 wp01, CF .8 – Z-234 wp02 is a planned wellpath and does not exist. It will be
drilled after Z-235, and will be in the OBd sand, giving it geologic separation from Z-
235
x Z-116, PB1, PB2 CF 1.0 = Z-116 is a sidetracked active borealis injector, Z-235 lateral
will TD short of crossing the EOU of Z-116. Z-116 will be shut in and a plug set in the
tubing tail
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
Z-116, PB1, PB2 CF 1.0 = Z-116 is a sidetracked active borealis injector, Z-235 lateral,, j,
will TD short of crossing the EOU of Z-116. Z-116 will be shut in and a plug set in the
tubing tail
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Drilling Procedure
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.19 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.20 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.21 POOH and LD BHA.
15.22 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
16.0 Run 4-1/2” Injection Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# W563 x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck 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.
16.3 Run 4-1/2” injection liner
x Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
x See data sheets on the next page for MU torque for the 4-1/2” liner connections.
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Drilling Procedure
16.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger with 150’ of overlap
x Confirm set depth with completion engineer.
x 3-5 joints of 7” H563 will be ran under the liner hanger for the production packer. Confirm
with completion engineer.
16.5 Ensure hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
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Drilling Procedure
16.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.5. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.6. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.7. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x Fill drill pipe on the fly Monitor FL and if filling is required due to losses/surging.
16.8. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.9. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.10. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.11. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.12. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.13. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.14. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
16.15. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
Page 36
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
16.16. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.17. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.18. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.19. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.20. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
Page 37
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 BTC tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, BTC
Confirm Torques with casing hand
=
17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs
Page 38
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
Page 39
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 JFEBear tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 13.5#, JFE Bear x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” GL completion jewelry (tally to be provided by
Operations Engineer):
x Torque Turn All Connections
x Tubing Jewelry to include:
x 1x ‘X’ Nipple
x 1x SSD
x 1x Production Packer
x 1x X Nipple
x 1x WLEG
x XXX joints, 4-1/2”, 12.6#, L-80, JFE Bear
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited KCL follow by ~150 bbls of diesel freeze
protect for both tubing and IA to 2,500’ TVD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
Page 40
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. CTU
a. Pull ball and rod in 4-1/2” production packer
24 hour notice for AOGCC opportunity to witness. -mgr
Page 41
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 42
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 43
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
21.0 Wellhead Schematic
Page 44
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
22.0 Days Vs Depth
Page 45
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV6 Ice 1,153 1,110.5 -1028 489 8.46
BPRF Water 2,418 1,945.5 -1863 856 8.46
SV3 Gas Hydrates 2,902 2,239.5 -2157 985 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: 2450' - 4050' MD
SV1 Gas Hydrates 3,785 2,776.5 -2694 1222 8.46
Ugnu 4A Heavy Oil 4,443 3,177.5 -3095 1398 8.46 Heavy Oil in Ugnu 4A: ~4400' - 4650' MD
UG3 Water 4,950 3,485.5 -3403 1534 8.46
Ugnu LA Water 6,018 4,135.5 -4053 1820 8.46 Possible Heavy Oil in Ugnu L Sands: ~6000' - 6300' MD
Ugnu MB Water 6,341 4,325.5 -4243 1903 8.46
NB Schrader Bluff Water 6,750 4,544.5 -4462 2000 8.46
OA Top Schrader Bluff Water 7,108 4,701.5 -4619 2069 8.46
ObA Top Schrader Bluff Water 7,265 4,757.5 -4675 2093 8.46
FAULT 60' DTN Throw 7,490
OBb Top Schrader Bluff Oil 7,575 4,841.5 -4759 2130 8.46
OBc Top (Heel) Schrader Bluff Oil 7,905 4,889.5 -4807 2151 8.46
OBc (Toe) 11,920 4,869.0 -4789 2142 8.46
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
Z-235 wp03ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
Gas Hydrates expected SV3, SV2, & SV1 sands: 2450' - 4050' MD
Page 46
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
Page 47
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have been seen on PBU Z Pad. They were reported between 1660’, 2740’, and 4000’
TVD. MW has been chosen based upon successful trouble free penetrations of offset wells.
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
o Reduce flowrate as needed to help control hydrates in the mud column.
Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not
prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been
disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible
while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone.
Excessive circulation will accelerate formation thawing which can increase the amount of hydrates
released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with
both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud
cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Page 48
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 49
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 50
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x Z-234 wp01, CF .8 – Z-234 wp02 is a planned wellpath and does not exist. It will be
drilled after Z-235, and will be in the OBd sand, giving it geologic separation from Z-
235
x Z-116, PB1, PB2 CF 1.0 = Z-116 is a sidetracked active borealis injector, Z-235 lateral
will TD short of crossing the EOU of Z-116. Z-116 will be shut in and a plug set in the
tubing tail
x
j,
Z-116 will be shut in and a plug set in the
tubing tail
Page 51
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
26.0 FIT 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.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 53
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
Z-235 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
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0425850127517002125255029753400382542504675True Vertical Depth (850 usft/in)-425 0 425 850 1275 1700 2125 2550 2975 3400 3825 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075Vertical Section at 1.70° (850 usft/in)Z-235 wp01 tgt1Z-235 wp01 tgt2Z-235 wp01 tgt3Z-235 wp03 toe tgt9 5/8" x 12 1/4"7" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500
9000
9500
10000
10500110001150011920Z-235 wp03Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 501.5' MD, 501.13'TVDEnd Dir : 1665.1' MD, 1488.38' TVDStart Dir 4º/100' : 5711.68' MD, 3949.09'TVDEnd Dir : 7877.72' MD, 4888.24' TVDStart Dir 3º/100' : 7927.72' MD, 4892.6'TVDEnd Dir : 8101.76' MD, 4899.85' TVDStart Dir 2.5º/100' : 9981.46' MD, 4892.6'TVDEnd Dir : 10103.9' MD, 4888.89' TVDStart Dir 2.5º/100' : 10832.83' MD, 4847.6'TVDEnd Dir : 11032.6' MD, 4844.69' TVDTotal Depth : 11920' MD, 4869.15' TVDSV6BPRFSV3SV1Ugnu 4AUG3Ugnu LAUgnu MBNBOAObAOBbOBcHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: Z-23556.10+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959240.04600033.50 70° 17' 52.9852 N 149° 11' 23.6348 WSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 1200.00 Z-235 wp03 (Z-235) GYD_Quest GWD1200.00 7930.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+Sag7930.00 11920.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1110.60 1028.00 1151.73 SV61945.60 1863.00 2416.99 BPRF2239.60 2157.00 2900.46 SV32776.60 2694.00 3783.54 SV13177.60 3095.00 4442.98 Ugnu 4A3485.60 3403.00 4949.48 UG34135.60 4053.00 6017.95 Ugnu LA4325.60 4243.00 6339.24 Ugnu MB4544.60 4462.00 6748.73 NB4701.60 4619.00 7105.93 OA4757.60 4675.00 7262.29 ObA4841.60 4759.00 7569.35 OBb4889.60 4807.00 7893.30 OBcREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-235, True NorthVertical (TVD) Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)Measured Depth Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)Calculation Method:Minimum CurvatureProject:Prudhoe BaySite:ZWell:Plan: Z-235Wellbore:Z-235Design:Z-235 wp03CASING DETAILSTVD TVDSS MD SizeName4892.80 4810.20 7930.00 9-5/8 9 5/8" x 12 1/4"4869.15 4786.55 11920.00 7 7" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 501.50 6.05 85.00 501.13 0.93 10.58 3.00 85.00 1.24 Start Dir 4º/100' : 501.5' MD, 501.13'TVD4 1665.10 52.55 91.40 1488.38 -5.33 564.13 4.00 7.00 11.40 End Dir : 1665.1' MD, 1488.38' TVD5 5711.68 52.55 91.40 3949.09 -83.58 3775.60 0.00 0.00 28.46 Start Dir 4º/100' : 5711.68' MD, 3949.09'TVD6 7877.72 85.00 1.80 4888.24 1235.30 4889.91 4.00 -93.73 1379.82 End Dir : 7877.72' MD, 4888.24' TVD7 7927.72 85.00 1.80 4892.60 1285.08 4891.47 0.00 0.00 1429.63 Z-235 wp01 tgt1 Start Dir 3º/100' : 7927.72' MD, 4892.6'TVD8 8101.76 90.22 1.79 4899.85 1458.82 4896.92 3.00 -0.06 1603.45 End Dir : 8101.76' MD, 4899.85' TVD9 9981.46 90.22 1.79 4892.60 3337.59 4955.80 0.00 0.00 3483.14 Z-235 wp01 tgt2 Start Dir 2.5º/100' : 9981.46' MD, 4892.6'TVD10 10103.90 93.25 1.34 4888.89 3459.92 4959.15 2.50 -8.61 3605.51 End Dir : 10103.9' MD, 4888.89' TVD11 10832.83 93.25 1.34 4847.60 4187.47 4976.12 0.00 0.00 4333.25 Z-235 wp01 tgt3 Start Dir 2.5º/100' : 10832.83' MD, 4847.6'TVD12 11032.60 88.42 2.62 4844.69 4387.04 4983.01 2.50 165.11 4532.94 End Dir : 11032.6' MD, 4844.69' TVD13 11920.00 88.42 2.62 4869.15 5273.18 5023.53 0.00 0.00 5419.89 Z-235 wp03 toe tgt Total Depth : 11920' MD, 4869.15' TVD
-800
-400
0
400
800
1200
1600
2000
2400
2800
3200
3600
4000
4400
4800
5200
5600
6000
South(-)/North(+) (800 usft/in)-400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200
West(-)/East(+) (800 usft/in)
Z-235 wp03 toe tgt
Z-235 wp01 tgt3
Z-235 wp01 tgt2
Z-235 wp01 tgt1
9 5/8" x 12 1/4"
7" x 8 1/2"
2507
50100012501500175020002250250027503000325035003750400042504
5
0
0
4750
4869
Z-235 wp03
Start Dir 3º/100' : 300' MD, 300'TVD
Start Dir 4º/100' : 501.5' MD, 501.13'TVD
End Dir : 1665.1' MD, 1488.38' TVD
Start Dir 4º/100' : 5711.68' MD, 3949.09'TVD
End Dir : 7877.72' MD, 4888.24' TVD
Start Dir 3º/100' : 7927.72' MD, 4892.6'TVD
End Dir : 8101.76' MD, 4899.85' TVD
Start Dir 2.5º/100' : 9981.46' MD, 4892.6'TVD
End Dir : 10103.9' MD, 4888.89' TVD
Start Dir 2.5º/100' : 10832.83' MD, 4847.6'TVD
End Dir : 11032.6' MD, 4844.69' TVD
Total Depth : 11920' MD, 4869.15' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4892.80 4810.20 7930.00 9-5/8 9 5/8" x 12 1/4"
4869.15 4786.55 11920.00 7 7" x 8 1/2"
Project: Prudhoe Bay
Site: Z
Well: Plan: Z-235
Wellbore: Z-235
Plan: Z-235 wp03
WELL DETAILS: Plan: Z-235
56.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5959240.04 600033.50 70° 17' 52.9852 N 149° 11' 23.6348 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: Z-235, True North
Vertical (TVD) Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)
Measured Depth Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)
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)Z-234 wp02Z-210PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Z-235 NAD 1927 (NADCON CONUS)Alaska Zone 0456.10+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959240.04600033.50 70° 17' 52.9852 N 149° 11' 23.6348 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-235, True NorthVertical (TVD) Reference: Z-235 as built RKB @ 82.60usft (Original Well Elev)Measured Depth Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 Z-235 wp03 (Z-235) GYD_Quest GWD1200.00 7930.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+Sag7930.00 11920.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+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)Z-234 wp02Z-234 wp02Z-234 wp02Z-113Z-115Z-61Z-69NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 11920.00Project: Prudhoe BaySite: ZWell: Plan: Z-235Wellbore: Z-235Plan: Z-235 wp03Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4892.80 4810.20 7930.00 9-5/8 9 5/8" x 12 1/4"4869.15 4786.55 11920.00 7 7" x 8 1/2"
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0.001.002.003.004.00Separation Factor8100 8325 8550 8775 9000 9225 9450 9675 9900 10125 10350 10575 10800 11025 11250 11475 11700 11925 12150Measured Depth (450 usft/in)W-26BZ-234 wp02Z-116Z-210PB1No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Z-235 NAD 1927 (NADCON CONUS)Alaska Zone 0456.10+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959240.04600033.5070° 17' 52.9852 N149° 11' 23.6348 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-235, True NorthVertical (TVD) Reference: Z-235 as built RKB @ 82.60usft (Original Well Elev)Measured Depth Reference:Z-235 as built RKB @ 82.60usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 Z-235 wp03 (Z-235) GYD_Quest GWD1200.00 7930.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+Sag7930.00 11920.00 Z-235 wp03 (Z-235) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8100 8325 8550 8775 9000 9225 9450 9675 9900 10125 10350 10575 10800 11025 11250 11475 11700 11925 12150Measured Depth (450 usft/in)Z-234 wp02NO GLOBAL FILTER: Using user defined selection & filtering criteria26.50 To 11920.00Project: Prudhoe BaySite: ZWell: Plan: Z-235Wellbore: Z-235Plan: Z-235 wp03Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4892.80 4810.20 7930.00 9-5/8 9 5/8" x 12 1/4"4869.15 4786.55 11920.00 7 7" x 8 1/2"
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.
PRUDHOE BAY SCHRADER BLUF OIL
223-055
PBU Z-235
ECKLISTpanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN Z-235Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore sAnnular DisPRUDHOE BAY, SCHRADER BLUF OIL - 640135NAPermit fee attachedYes Entire Well lies within ADL0028262.Lease number appropriateYesUnique well name and numberYes PRUDHOE BAY, SCHRADER BLUF OIL - governed by CO 505B, CO 505B.004Well located in a defined poolYesWell located proper distance from drilling unit boundaryYesWell located proper distance from other wellsYesSufficient acreage available in drilling unitYesIf deviated, is wellbore plat includedYesOperator only affected partyYes0Operator has appropriate bond in forceYesPermit can be issued without conservation orderYes2Permit can be issued without administrative approvalYes Governed by AIO 26B, issued May 4, 2010, omits part of Affected Area. Correction to3Can permit be approved before 15-day waitYes Affected Area issued March 15,2014. Text error within order corrected February 3, 2021.4Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes PBU Z-116, PBU Z-228, PBU Z-229, PBU W-26B, PBU W-241, PBU Z-210PB15All wells within 1/4 mile area of review identified (For service well only)No6Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA7Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 105'8Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir9Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.0CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.2CMT will cover all known productive horizonsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.3Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support4Adequate tankage or reserve pitYes This is a grassroots well.5If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches.6Adequate wellbore separation proposedYes 16" Diverter below BOPE7If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.8Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.9BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.0BOPE press rating appropriate; test to (put psig in comments)YesChoke manifold complies w/API RP-53 (May 84)Yes2Work will occur without operation shutdownYes Monitoring will be required.3Is presence of H2S gas probableYes4Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. Z-Pad wells are H2S bearing.5Permit can be issued w/o hydrogen sulfide measuresYes Gas hydrates expected from Base Permafrost to Top Ugnu. Mitigation measures discussed6Data presented on potential overpressure zonesNA in Drilling Hazards. A 60' vertical-displacement fault expected at 7490' MD (-4740' TVDSS).7Seismic analysis of shallow gas zonesNA Normal pressures expected; MPD will mitigate any abnormal pressures encountered.8Seabed condition survey (if off-shore)NA CaCO3 onsite to weight up mud system to 1 ppg above highest anticipated mud weight.9Contact name/phone for weekly progress reports [exploratory only]Date:Engineering Commissioner:DatePublic CommissionerDateGCW 07/13/2023
