Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout224-1417. 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 M-207
Establish MI Inj per AIO25A.027
Hilcorp North Slope, LLC
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
224-141
50-029-23807-00-00
15500
Conductor
Surface
Tieback
Production
Liner
5174
80
6427
5548
9926
15420
20"
9-5/8"
7"
7" x 4-1/2"
5175
26 - 106
26 - 6453
24 - 5572
5564 - 15490
26 - 106
26 - 5141
24 - 4877
4872 - 5174
None
3090
5410
5410 / 7500
None
5750
7240
7240 / 8430
6621 - 15247
4-1/2" 12.6# L-80 22 - 6458
5152 - 5176
Structural
4-1/2" HES TNT Perm Packer
5809
4990
Torin Roschinger
Operations Manager
Hunter Gates
hunter.gates@hilcorp.com
(907) 777-8326
PRUDHOE BAY, POLARIS OIL
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 028257, 028260
22 - 5142
N/A
N/A
2672
401 1974
3030
N/A
13b. Pools active after work:POLARIS OIL
No SSSV Installed
5809, 4990
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 9:17 am, Jun 17, 2025
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662)
Date: 2025.06.17 07:00:41 -
08'00'
Torin Roschinger
(4662)
JJL 6/30/25 DSR-6/18/25
ACTIVITY DATE SUMMARY
5/27/2025
T/I/O = 1600/0/0 Hot Diesel Breakover ( WAG SWAP ) Pumped 2 bbls of 60/40 & 98
bbls of 180*F DSL down TBG. Pad Op notified upon departure.
FWHP = 2450/0/0
Daily Report of Well Operations
PBU M-207
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: 5/08/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250508
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 241-26 50283201970000 224068 4/15/2025 AK E-LINE Perf
BRU 244-27 50283201850000 222038 4/19/2025 AK E-LINE Perf
IRU 11-06 50283201300000 208184 4/14/2025 AK E-LINE CIBP
PBU S-22B 50029221190200 197051 4/15/2025 AK E-LINE IPROF
SRU 231-33 50133101630100 223008 4/13/2025 AK E-LINE CIBP
PBU 14-33B 50029210020200 223067 1/22/2025 BAKER MRPM
END 1-65A 50029226270100 203312 4/15/2025 HALLIBURTON COILFLAG
END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON LDL
END 2-72 50029237810000 224016 4/11/2025 HALLIBURTON MFC40
MPU R-105 50029238150000 225017 4/20/2025 HALLIBURTON CAST-CBL
NS-19 50029231220000 202207 4/12/2025 HALLIBURTON RBT
PBU 06-12B 50029204560200 211115 3/22/2025 HALLIBURTON RBT
PBU 07-22A 50029209250200 212085 3/31/2025 HALLIBURTON RBT
PBU B-30B 50029215420100 201105 4/9/2025 HALLIBURTON RBT-COILFLAG
PBU H-17A 50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG
PBU H-29B 50029218130200 225005 5/1/2025 HALLIBURTON RBT
PBU J-10B 50029204440200 215112 4/15/2025 HALLIBURTON RBT
PBU M-207 50029238070000 224141 4/21/2025 HALLIBURTON IPROF
PBU Z-25 50029219020000 188159 4/23/2025 HALLIBURTON IPROF
PBU Z-31 50029218710000 188112 4/25/2025 HALLIBURTON IPROF
Please include current contact information if different from above.
T40372
T40373
T40374
T40375
T40376
T40377
T40378
T40379
T40379
T40380
T40381
T40382
T40383
T40384
T40385
T40386
T40387
T40388
T40389
T40390
PBU M-207 50029238070000 224141 4/21/2025 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.08 12:42:44 -08'00'
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/10/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#2025010
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BRU 211-26 50283201280000 208112 1/27/2025 AK E-LINE PPROF
T40287
END 1-41 50029217130000 187032 3/13/2025 HALLIBURTON MFC40
T40288
END 2-14 50029216390000 186149 3/12/2025 HALLIBURTON MFC40
T40289
END 3-33A 50029216680100 203215 3/23/2025 HALLIBURTON COILFLAG
T40290
GP AN-17A 50733203110100 213049 12/29/2024 AK E-LINE Perf
T40291
KALOTSA 3 50133206610000 217028 3/3/2025 AK E-LINE PPROF
T40292
KU 12-17 50133205770000 208089 1/28/2025 AK E-LINE Perf
T40293
MPI 2-14 50029216390000 186149 2/17/2025 AK E-LINE Plug/Cement
T40294
NCIU A-21 50883201990000 224086 3/28/2025 AK E-LINE Plug-Perf
T40295
ODSN-25 50703206560000 212030 3/7/2025 HALLIBURTON CORRELATION
T40296
PBU 02-08B 50029201550200 198095 3/17/2025 HALLIBURTON RBT
T40297
PBU D-08B 50029203720200 225007 3/22/2025 HALLIBURTON RBT
T40298
PBU J-25B 50029217410200 224134 3/10/2025 HALLIBURTON RBT
T40299
PBU K-12D 50029217590400 224099 3/18/2025 HALLIBURTON RBT
T40300
PBU K-19B 50029225310200 215182 3/27/2025 HALLIBURTON RBT
T40301
PBU L1-15A 50029219950100 203120 3/27/2025 HALLIBURTON PPROF
T40302
PBU M-207 50029238070000 224141 3/18/2025 HALLIBURTON IPROF
T40303
PBU P1-04 50029223660000 193063 3/28/2025 HALLIBURTON PPROF
T40304
PBU W-220A 50029234320100 224161 3/11/2025 HALLIBURTON RBT
T40305
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40303PBU M-207 50029238070000 224141 3/18/2025 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.04.10 13:48:56 -08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, March 13, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Bob Noble
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
M-207
PRUDHOE BAY UN POL M-207
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/13/2025
M-207
50-029-23807-00-00
224-141-0
W
SPT
4990
2241410 3500
1632 1634 1629 1631
135 300 287 282
INITAL P
Bob Noble
1/13/2025
MIT-IA to 3500 psi post initial injection.
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 POL M-207
Inspection Date:
Tubing
OA
Packer Depth
146 3731 3683 3677IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitRCN250113161102
BBL Pumped:2.2 BBL Returned:1.8
Thursday, March 13, 2025 Page 1 of 1
9
9
9
9
9 9
999
9 9
99
9
9
9
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.13 10:08:20 -08'00'
A&e a rl� t1(,Lif- M -Z07
Regg, James B (OGQ 2.7A 14 10
From:
Brooks, Phoebe L (OGC)
Sent:
Tuesday, January 21, 2025 5:22 PM
To:
Clint Montague - (C)
Cc:
Regg, James B (OGC)
Subject:
RE: 10-426
Attachments:
MIT PBLI M-207 12-13-24 Revised.xlsx
Clint,
:r
Attached is a revised report correcting the formatting (PTD # now reflects 2241410 and moving the Waived by remarks
to the Notes) and adding the type of test to the Notes. Please update your copy or let me know if you disagree.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907-793-1242
CONFIDENTIALITYN077CE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska_gov.
From: Clint Montague - (C) <cmontague@hilcorp.com>
Sent: Saturday, December 14, 2024 9:42 AM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris
D (OGC) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>
Cc: PB Wells Integrity <PBWellsintegrity@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>
Subject: 10-426
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.
Attached is the 10-426 form for the MIT-T and MIT -IA from PBU M-207 post completion run.
Let me know if you have any questions.
Clint Montague
Hilcorp DSM Innovation
907-670-3094 Office
907-394-0776 Cell
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
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Submit to: 'imireaalffialaska.aov.
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
AOGCC. Insoectors0alaska.gov: Droop. brooksOalaska.gov
Hilcorp North Slope LLC
Prudhoe Bay I PBU / M-Pad / M-207
Clinton Montague I Sam Menapace
chris Wallaceitalaska.00v
Well
M-207
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
41
22410
Type Inj
N i
Tubing
0
3704 .
3614
3608-
Type Test
P
Packer TVD
4990
BBLPump
2.5 -
IA
0
0
0
0 -
Interval
I
Test psi
-
3500
BBL Return
2,4
OA
0 -
0
0
0
Result
P
Notest:
MIT-T. Waived by Austin McLeod ✓
Well
M-207
Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min.
PTD
2241410
Type In)
N
Tubing
1150
1825
1843
1W3
Type Test
P
Packer TVO
4990
BBLPump
3.5
IA
0
W20
3530
3515
Interval
Test psi
3500
BBL Return
3A
OA
0
0
0
1 0
Result
P
Notes:
MIT -IA to 3600 psi per PTD. Waived by Austin McLeod
Well
I Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer WO
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
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
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type Test
Packer TVD
BBLPump
IA
Interval
Test psi
BBL Return
OA
Resuk
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTD
Type Inj
Tubing
Type TBsI
Packer TVD
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Notes:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type lnj
Tubing
Type Test
Packer TVD
BBLPump
IA
Interval
Test psi
BBL Return
OA
Result
Nabs:
Well
Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min.
PTO
Type Inl
Tubing
Type Test
Packer WD
BBL Pump
IA
Interval
Test psi
BBL Return
OA
Result
NPMs:
TYPE INJ CO.
W=water
G-Gas
S a Slurry
I=Industrial Wameeetcl
N=Na 11.1
TYPE TEST Codes
P - Pressure TM
O = older (deacdte In Novel
INTERVALC.
I = Initial Test
4=Four Year Cycle
V = Race. Oy Variance,
0 = Mer tdeurbe is nmeq
Result CMes
P v Pan
F=Fail
I = IncoMlaeive
Form 10426 (Revised 0112017) MIT PBU M-M712.13-24 Revised
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: 1/16/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240116
Well API #PTD #Log Date Log
Company Log Type AOGCC
ESet #
BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL
BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF
BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF
BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF
BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF
GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL
GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL
GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf
GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL
IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug
IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination
KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf
MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord
MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech
MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF
MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf
MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf
MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf
PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF
PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT
PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT
PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP
PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT
PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF
PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT
PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF
PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT
TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf
T39958
T39959
T39960
T39961
T39962
T39963
T39964
T39964
T39965
T39966
T39966
T39967
T39968
T39969
T39970
T39970
T39971
T39971
T39972
T39973
T39974
T39975
T39976
T39977
T39978
T39979
T39980
T39981
PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.01.16 13:56:40 -09'00'
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
Date: 01/07/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
PBU M-207 + PB1
PTD: 224-141
API: 50-029-23807-00-00 (PBU M-207)
API: 50-029-23807-70-00 (PBU M-207PB1)
FINAL LWD FORMATION EVALUATION + GEOSTEERING (11/19/2024 to 12/04/2024)
x ROP, BaseStar & ABG Gamma Ray, M5-EWR &StrataStar Resistivity, Horizontal Presentation
(2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Geosteering and EOW Report
SFTP Transfer – Main Folders:
PBU M-207 + PB1 LWD Subfolders:
PBU M-207 Geosteering Subfolders: g
Please include current contact information if different from above.
T39939
T39940
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.01.08 08:20:13 -09'00'
4
By James Brooks at 8:33 am, Jan 08, 2025
Complete
12/14/2024
JSB
RBDMS JSB 011025
G
SFD 2/7/2025JJL 5/6/25
DSR-4/7/25
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2025.01.07 13:19:04 -
09'00'
Sean
McLaughlin
(4311)
5582' 4882'
5862' 5011'
6336' 5126'
239
400
735
06:00 RDMO
1.741,925
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Wallace, Chris D (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: PBU M-207 PTD #224-141 Clarifications
Date:Tuesday, December 10, 2024 12:10:11 PM
From: Wallace, Chris D (OGC)
Sent: Monday, December 9, 2024 6:45 PM
To: Tyson Shriver <Tyson.Shriver@hilcorp.com>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Roby,
David S (OGC) <dave.roby@alaska.gov>
Subject: RE: PBU M-207 PTD #224-141 Clarifications
Tyson,
AOGCC approves the variance request to not perform the step rate test or surveillance log (AIO 25A
Rule 4 requirement) for this well. Instead, the well will be limited to the 0.8 psi/ft injection pressure.
Looking at AIO 25A, wells have individually been approved for enriched hydrocarbon gas (Rich Gas)
via the AIO administrative approval process.
You can utilize the same process, and provide the same information, as AIO 25A.025 for S-104 (PTD
2001960) which looks like the most recently issued.
Information to support the AIO and regulation requirements for confirming/passing zonal isolation
and well integrity etc for M-207 should be included with the AA request as this information will not
have been previously provided to the commission due to the new drill.
Hilcorp could evaluate how many additional wells are in this situation, and determine if an update to
the 20 year old AIO 25A would be more efficient than doing this well by well.
Thanks and Regards,
Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907)
793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska
Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended
recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure
of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please
delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you,
contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov.
From: Tyson Shriver <Tyson.Shriver@hilcorp.com>
Sent: Monday, December 9, 2024 3:56 PM
To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>
Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>
Subject: PBU M-207 PTD #224-141 Clarifications
Mr. Wallace,
I am looking for a couple clarifications on the approved PBU M-207 PTD (#224-141). The
approved PTD is attached for quick reference.
M-207 was permitted as a WAG injector in the Polaris Oil Pool. Per Rule 2 of AIO 25A “The
underground injection of enriched gas for enhanced oil recovery is authorized only in the follow
wells: S-215i, W-209i, and W-215i. Upon proper application, the Commission may approve
additional wells for injection of enriched gas within the Polaris Oil Pool.” Please let me know if
the PTD for M-207 is a proper application or a separate Administrative Approval is needed for
enriched hydrocarbon gas injection.
A variance was requested to AIO 25A Rule 4 to not perform a step rate test or surveillance log
within three months of start of injection (page #8 of the drilling program). I do not see any
comments approving or denying the variance request in the approved PTD. Could you please
confirm if Hilcorp’s variance request to AIO 25A Rule 4 is approved?
Thank you,
Tyson Shriver
Hilcorp Alaska
PBW GC2 OE (L, V, W, Z)
o: 907-564-4542
c: 406-690-6385
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Rixse, Melvin G (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: HAK PBU M-207 (PTD: 224-141) Surface Casing Test and FIT
Date:Friday, November 29, 2024 10:33:19 AM
Attachments:HAK PBU M-207 Surface Casing Test & FIT.pdf
From: Joseph Engel <jengel@hilcorp.com>
Sent: Friday, November 29, 2024 9:58 AM
To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Subject: HAK PBU M-207 (PTD: 224-141) Surface Casing Test and FIT
Mel –
Attached is the surface casing test and FIT for PBU M-207.
The two stage cement job went well.
First Stage: circulated 72bbl of cement to surface through stage tool, with full
returns throughout the job
Second Stage: circulated 278 bbl of cement to surface, with full returns
throughout the job
Please let me know if you have any questions.
Joe
Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC
Office: 907.777.8395 | Cell: 805.235.6265
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBW M-207 Date:11/28/2024
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Lott/Yearout
Csg Setting Depth:6,453 TMD 5140 TVD
Mud Weight:9.2 ppg LOT / FIT Press =770 psi
LOT / FIT =12.08 ppg Hole Depth =6483 md
Fluid Pumped=1.3 Bbls Volume Back =1.0 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
->0 40 ->0 0
->2 100 ->6 260
->4 180 ->12 500
->6 263 ->18 693
->8 346 ->24 882
->10 420 ->30 1092
->12 490 ->36 1326
->14 555 ->42 1535
->16 626 ->48 1771
->18 681 ->54 1999
->20 770 ->60 2233
->22 ->66 2473
->24 ->74 2760
->27 ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 770 ->0 2760
->1 737 ->1 2754
->2 722 ->2 2751
->3 708 ->3 2749
->4 694 ->4 2748
->5 683 ->5 2745
->6672 ->10 2740
->7661 ->15 2734
->8652 ->20 2729
->9643 ->25 2726
->10 635 ->30 2722
-> ->35 2719
-> ->
-> ->
0
2
4
6
8
10
12
14
16
18
20
0
6
12
18
24
30
36
42
48
54
60
66
74
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 1020304050607080Pressure (psi)Strokes (# of)
LOT / FIT DATA CASING TEST DATA
770737722708694683672661652643635
276027542751274927482745 2740 2734 2729 2726 2722
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 5 10 15 20 25 30Pressure (psi)Time (Minutes)
LOT / FIT DATA CASING TEST DATA
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________PRUDHOE BAY UN POL M-207
JBR 01/29/2025
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
Test with 4-1/2", 5" and 7" TJ's Accumulator bottles 20 bottles with 1000 psi avg
Test Results
TEST DATA
Rig Rep:Vanhoose/EvansOperator:Hilcorp North Slope, LLC Operator Rep:James Lott
Rig Owner/Rig No.:Hilcorp Innovation PTD#:2241410 DATE:11/27/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopKPS241127155353
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 4
MASP:
1745
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 2 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 P
#2 Rams 1 Blinds P
#3 Rams 1 7" Fixed 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 2 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1450
200 PSI Attained P32
Full Pressure Attained P114
Blind Switch Covers:YAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@2350
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P12
#1 Rams P9
#2 Rams P9
#3 Rams P9
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9999
9
9
9
1
Dewhurst, Andrew D (OGC)
From:Rixse, Melvin G (OGC)
Sent:Wednesday, 13 November, 2024 15:10
To:Sean McLaughlin
Cc:Aras Worthington; Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Dewhurst, Andrew
D (OGC); Joseph Lastufka; Torin.Roschinger@hilcorp.com; Lau, Jack J (OGC); Roby, David
S (OGC)
Subject:RE: [EXTERNAL] RE: PBU M-207 New Spud Date and Permit to Drill Approval Request
Sean,
After internal discussions with AOGCC staƯ, it is improbable that AOGCC will be able to approve,
within 6 working days, a permit to drill for a SB WAG injector that is drilling within close proximity of one
of the most congested pads on the North Slope with legacy near proximity wells to 3 diƯerent reservoir
pools at 3 significantly diƯerent reservoir pressures.
Mel Rixse
Senior Petroleum Engineer (PE)
Alaska Oil and Gas Conservation Commission
907-793-1231 OƯice
907-297-8474 Cell
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized
review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first
saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or
(Melvin.Rixse@alaska.gov).
From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>
Sent: Wednesday, November 13, 2024 1:15 PM
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies,
Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Subject: RE: [EXTERNAL] RE: PBU M-207 New Spud Date and Permit to Drill Approval Request
Andy,
Please know that the M-207 rush request was not a result of poor planning. A failed drilling attempt on well13-24
caused the removal of the subsequent two wells due to high risk. The decision to remove 80 days of planned work
from the drilling schedule was not taken lightly but was the best course of action for risk management.
Please consider a verbal approval to nipple up the diverter, drill surface hole, run casing, and cement. The surface
hole section is well understood and drilling on diverter is standard. Is it possible a partial scope of work can be
approved before the weekend? Hilcorp understands that partial approval is no guarantee of full approval and
assumes that risk.
Regards,
Sean
2
From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>
Sent: Wednesday, November 13, 2024 12:32 PM
To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>; Rixse,
Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D
(OGC) <meredith.guhl@alaska.gov>
Subject: [EXTERNAL] RE: PBU M-207 New Spud Date and Permit to Drill Approval Request
Joe,
We will not be able to meet this requested Ɵmeline for the PBU M-207 PTD. I understand that Mel already spoke with
Torin Roschinger about this.
Also see this noƟce regarding rush requests.
Andy
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Wednesday, 13 November, 2024 11:54
To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>
Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>
Subject: PBU M-207 New Spud Date and Permit to Drill Approval Request
Andy,
Per our phone conversation, the new spud date for PBU M-207 is Friday 11/15. If we could have approval by end of
day on the 15th that would be absolutely great. As also discussed, we will endeavor to have the next planned PTD
submitted as soon as possible and try to maintain a hopper to eliminate these rush requests whenever possible in
the future.
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
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.
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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
Sean McLaughlin
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Polaris Oil Pool, PBU M-207
Hilcorp Alaska, LLC
Permit to Drill Number: 224-141
Surface Location: 3492' FSL, 605' FEL, Sec. 01, T11N, R12E, UM, AK
Bottomhole Location: 679' FSL, 2079' FWL, Sec. 26, T12N, R12E, UM, AK
DearMr. McLaughlin:
Enclosed is the approved application for the permit to drill the abovereferenced well.
PerStatute 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 AOGCCreserves
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 AOGCCspecifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or anAOGCCorder, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
*UHJRU\&:LOVRQ
Commissioner
DATED this 19thday of November 2024.
Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.11.19 12:22:34 -09'00'
Digitally signed by Sean
McLaughlin (4311)
DN: cn=Sean McLaughlin (4311)
Date: 2024.11.07 16:24:03 -
09'00'
Sean
McLaughlin
(4311)
By Grace Christianson at 8:09 am, Nov 08, 2024
A.Dewhurst 18NOV24
DSR-11/19/24
* BOPE test to 3000 psi. Annular to 2500 psi.
* MIT-IA to 3500 psi. 24 hour notice for opportunity to witness.
* MIT-IA to 3500 psi within 7 days of stabilized injection.
* Variance to 20 AAC 25.412(b) - Approved for packer placement > 200' MD above the Polaris Oil
Pool. Packer to be place within the top confining zones of the Polaris Oil Pool.
MGR14NOV2024
224-141 50-029-23807-00-00
JLC 11/19/2024
Gregory Wilson Digitally signed by Gregory Wilson
Date: 2024.11.19 12:20:46 -09'00'
11/19/24
11/19/24
RBDMS JSB 112024
26
3635
12 M-01
M-02PB1
M-03
M-03A
M-03APB1
M-04
M-05M-05AM-05APB1M-05APB2
M-06
M-06A
M-07M-08
M-08A
M-08APB1M-08APB2
M-09
M-09A
M-09B
M-10
M-11
M-12M-12AM-13 M-13A
M-14
M-15
M-16
M-18
M-18A
M-18B
M-19
M-19A
M-19B M-20
M-20AM-20APB1
M-21
M-21A
M-22
M-23
M-23A
M-24
M-24A
M-26
M-26A
M-27
M-27A M-28
M-29
M-29A
M-30
M-31
M-32 M-33
M-34
M-38
M-38A
M-38APB1
NKUPST
R-11A
R-14A
R-28A
R-31A
-01
-01A
S-01B
S-01C
S-02
S-02A
S-02AL1
S-02AL1PB1
S-02APB1
S-04
S-05
S-05A
S-05APB1
S-06
S-07S-07A
S-08
S-08AS-08B
S-09
S-09A
S-09APB1
S-09APB2
S-09APB3
S-10
S-104
S-105
S-105A
S-108
S-109
S-109PB1
S-10A
S-10APB1S-10APB2
S-11
S-110
S-110A
S-110B
S-111
S-111PB1
S-111PB2
S-112S-112L1S-112L1PB1S-112L1PB2
S-118
S-11A
S-11B
S-12
S-121
S-121PB1
-122PB1
S-122PB2
122PB3
S-123
S-124
S-128PB1
S-129
S-12AS-12B
S-13
S-13A
S-14
S-14A
S-15 S-15PB1
S-16
S-16PB1
S-17
S-17A
S-17AL1S-17AL1PB1S-17APB1
-17B
-17C
S-17CPB1S-17CPB2
S-18
S-18A
S-18B
S-19
S-20
S-200PB1
S-201A
S-201PB1
S-202L1
S-202L2
S-202L3
S-202L4
S-20A
S-21
S-210
S-213AL2
S-215
S-216
S-217
S-218
S-22
S-22A
S-22B
S-23
S-24
A
S-24APB1
S-24B
S-25APB1
S-26S-27S-27AS-27APB1S-27B
S-28
S-28AS-28BS-28BPB1
S-29
S-29A
S-29AL1
S-30
S-31
S-31A
S-32S-32A
S-33
S-34
S-35
S-36S-37S-37AS-37APB1S-38
S-40
S-40A
S-41
S-42
S-42A
S-42PB1
S-43
S-43L1S-44S-44L1S-44L1PB1
S-504
M-201
M-200
M-202 Prop wp01
M-203 Prop wp01
M-204
M-205
M-207
S-24C_wp02
S-22C_WP01
HILCORP NORTH SLOPE
Greater Prudhoe Bay
M-207 AOR MAP
M-207 Proposed Location
FEET
0 1,000 2,000 3,000
POSTED WELL DATA
Well Name
WELL SYMBOLS
Location
INJ Well (Water Flood)
P&A Oil
P&A Oil/Gas
J&A
Temporarily Abandoned
Plugback
Active Oil
Injector Location
Producer Location
Shut in Injector
REMARKS
Well symbols at top of Schrader OA sand. Purple circle
and lines = 1320' radius from the OA sand in M-207. (OA
sand is top proposed sand for injection)
By: BCS -2024
October 22, 2024
Well Name PTD API Distance / StatusTop of Oil Pool(SB OA, MD)Top of Oil Pool(SB OA, TVD)Top of Cmt(MD)Top of Cmt(TVD)ZonalIsolationCommentsPBU M-200 222-031 50-029-23712-00-00 1361' / Producer 7754' 5084' Surface Surface ClosedTwo stage cement job, 9-5/8". First stage pumped 333 bbls 12.0 ppg Type I/II, followed by 82 bbls 15.8 ppg Type I/II cement.No losses noted. ES cementer opened at 2511' MD. 49.6 bbls of cement was circulated out to surface. Second stage cementjob pumped 249 bbls 10.7 ppg ArcticCem followed by 56.5 bbls 15.8 ppg Type I/II cement. Full returns throughout secondstage with a total of 208 bbls cement circulated to surface. Schrader Bluff OBd producer, not open to Schrader Bluff OA.PBU M-201 222-030 50-029-23711-00-00 262' / Injector 7523' 5145' Surface Surface ClosedTwo stage cement job, 9-5/8". First stage pumped 321 bbls 12.0 ppg Type I/II, followed by 87 bbls 15.8 ppg Type I/II cement.No losses noted. ES cementer opened at 2356' MD. 102 bbls of cement contaminated mud was circulated out to surface.Second stage cement job pumped 280 bbls 10.7 ppg ArcticCem followed by 56.5 bbls 15.8 ppg Type I/II cement. Full returnsthroughout second stage with a total of 212 bbls cement circulated to surface. Schrader Bluff OBd injector, not open toSchrader Bluff OA.PBU M-204 222-136 50-029-23735-00-00 990' / Producer 5943' 5127' Surface Surface ClosedTwo stage cement job, 9-5/8". First stage pumped 277 bbls 12.0 ppg Type I/II, followed by 82 bbls 15.8 ppg Type I/II cement.No losses noted. ES cementer opened at 2103' MD. 100 bbls of cement was circulated out to surface. Second stage cementjob pumped 287 bbls 10.7 ppg ArcticCem followed by 56 bbls 15.8 ppg Type I/II cement. Full returns throughout secondstage with a total of 200 bbls cement circulated to surface. Schrader Bluff OBa producer, not open to Schrader Bluff OA.PBU M-205 222-127 50-029-23733-00-00 1222' / Injector 6677' 5158' Surface Surface ClosedTwo stage cement job, 9-5/8". First stage pumped 334 bbls 12.0 ppg Type I/II, followed by 82 bbls 15.8 ppg Type I/II cement.No losses noted. ES cementer opened at 2084' MD. 73 bbls of cement was circulated out to surface. Second stage cementjob pumped 372 bbls 10.7 ppg ArcticCem followed by 56 bbls 15.8 ppg Type I/II cement. Full returns throughout secondstage with a total of 196 bbls cement circulated to surface. Schrader Bluff OBa injector, not open to Schrader Bluff OA.PBU M-206 224-130 50-029-23804-00-00 1036' / Prodcuer 6418' 5132' Surface Surface ClosedTwo stage cement job, 9-5/8". First stage pumped 246 bbls 12.0 ppg Type I/II, followed by 77.5 bbls 15.8 ppg Type I/IIcement. No losses noted. ES cementer opened at 2163' MD. 85 bbls of cement was circulated out to surface. Second stagecement job pumped 328 bbls 10.7 ppg ArcticCem followed by 56 bbls 15.8 ppg Type I/II cement. Full returns throughoutsecond stage with a total of 242 bbls cement circulated to surface. Schrader Bluff OBa injector, not open to Schrader BluffOA.PBU S-110 201-129 50-029-23030-00-00369' / P&A'd forSidetrack6807' 5186' 3466' 2883' ClosedPumped 165 bbls 12.0 ppg LiteCrete cement. 7" TOC logged at 3446' MD with USIT on 1/7/2012. Kuparuk P&A'd, not opento Schrader BluffPBU S-110A 211-129 50-029-23030-01-00164' / P&A'd forSidetrack6066' 5163' 4140' 3398' ClosedPumped 91.8 bbls 11.0 ppg LiteCrete followed by 34.2 bbls 15.8 ppg Class 'G' cement. 7" TOC logged at 4140' MD with USITon 2/13/2012. Kuparuk P&A'd, not open to Schrader BluffPBU S-110B 213-198 50-029-23030-02-00 974' / Injector 6590' 5206 5050' 4018' ClosedPumped 85 bbls 11.5 ppg LiteCrete followed by 35 bbls Class 'G'. 7" TOC logged at 5050' MD with USIT on 2/8/2014.Kuparuk injector, not open to Schrader Bluff.PBU S-124 206-136 50-029-23323-00-00 466' / Injector 8341' 5207' 5010' 3523' ClosedPumped 288 bbls 11.5 ppg LiteCrete followed by 138 bbls 15.8 ppg Class 'G' cement. 7" TOC logged at 5010' MD with USITon 11/8/2006. Kuparuk Injector, not open to Schrader Bluff.PBU S-13A 214-104 50-029-20810-01-00 251' / Producer 6895' 5196' 4670' 4269' ClosedTwo stage cement job. First stage pumped 85.4 bbls 12.0 ppg LiteCrete followed by 26.1 bbls 15.8 ppg Class 'G' cement. ESCementer opened at 7,873' MD. Second stage cement job pumped 85.1 bbls 15.3 ppg Class 'G' cement. 7" TOC logged at4660' MD with USIT on 9/30/2014. Remedial cement work squeezed 25 bbls 15.8 ppg Class 'G' cement into perforationsfrom 11,622' to 11,627' MD to isolate Sag and Kuparuk. Sag producer, not open to Schrader Bluff.PBU S-41 196-024 50-029-22645-00-00416' / P&A'd forSidetrack6895' 5171' 3228' 2969' ClosedPumped 179 bbls 11.0 ppg Class 'G' followed by 45 bbls 15.7 ppg Class 'G' cement. 7' TOC logged at 3228' MD with USIT on9/24/2010. Sag injector, not open to Schrader Bluff.Area of Review PBU M-207
Prudhoe Bay West
(PBU) M-207
Drilling Permit
Version 1
10/30/2024
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 & Cement 7” x 4-1/2” Injection Liner ............................................................................ 34
17.0 Run 7” Tieback ....................................................................................................................... 41
18.0 Run Upper Completion/ Post Rig Work ................................................................................ 44
19.0 Innovation Rig Diverter Schematic ........................................................................................ 47
20.0 Innovation Rig BOP Schematic .............................................................................................. 48
21.0 Wellhead Schematic ................................................................................................................ 49
22.0 Days Vs Depth ......................................................................................................................... 50
23.0 Formation Tops & Information.............................................................................................. 51
24.0 Anticipated Drilling Hazards ................................................................................................. 52
25.0 Innovation Rig Layout ............................................................................................................ 56
26.0 FIT Procedure ......................................................................................................................... 57
27.0 Innovation Rig Choke Manifold Schematic ........................................................................... 58
28.0 Casing Design .......................................................................................................................... 59
29.0 8-1/2” Hole Section MASP ...................................................................................................... 60
30.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 61
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................ 62
Page 2
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU M-207
Pad Prudhoe Bay M Pad
Planned Completion Type 4-1/2” Injection
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 17,637’ MD / 5213’ TVD
PBTD, MD / TVD 17,517’ MD / 5210’ TVD
Surface Location (Governmental) 3492' FSL, 605' FEL, Sec 01, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 628,208.4, Y=5,974,568.8
Top of Productive Horizon
(Governmental)121' FSL, 2410' FWL, Sec 36, T12N, R12E, UM, AK
TPH Location (NAD 27) X= 625,911.8 , Y=5,976,438.1
BHL (Governmental) 679' FNL, 2079' FWL, Sec 26, T12N, R12E, UM, AK
BHL (NAD 27) X= 620,133.7, Y= 5,986,103.4
AFE Number 241-00159
AFE Drilling Days 25
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1745 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2294 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 26.4 ft = 52.9 ft
GL Elevation above MSL: 26.4 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
M-207 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-52 Weld
12-1/4”9-5/8” 8.835 8.679 10.625 40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681 8.525 10.625 47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,240 5,410 604
8-1/2” 7” 6.276 6.151 7.656 26 L-80 563 7,240 5,410 604
4-1/2” 3.958 3.833 5.200 12.6 L-80 563 8,430 7,500 288
Tubing 4-1/2” 3.958 3.833 5.000 12.6 L-80 JFEBear 8,430 7,500 288
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).
Page 5
Prudhoe Bay West
M-207 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 Tyson Shriver 907.564.4542 tyson.shriver@hilcorp
Geologist Ben Siks 907.777.8388 bsiks@hilcorp.com
Reservoir Engineer Adam Lewis 907.777.8409 Adam.lewis@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: TJS 11/5/2024
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU M-207
Last Completed: TBD
PTD: TBD
OPEN HOLE / CEMENT DETAIL
42” 15 yds Concrete
12-1/4"Stg 1 – Lead – 506 sx / Tail – 395 sx
Stg 2 – Lead – 763 sx / Tail – 270 sx
8-1/2” Single Stage - 2365 sks
TD =17,637’(MD) / TD =5,214’(TVD)
4
20”
Orig. KB Elev.: 52.9’ / GL Elev.: 26.4’
8
3
9-5/8”
1
See
Liner
Detail
2
PBTD = 17,517’(MD) / PBTD = 5,210’(TVD)
9-5/8” ‘ES’
Cementer @
±2,500’
7
9
6
6
5
8 7
9999999999999
6666666666666666666666666666
6
5
4
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 80’ N/A
9-5/8" Surface 47/ L-80 / TXP 8.681 Surface ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 ~2,500’ 6,422’ 0.0758
7” Tieback 26 / L-80 / BTC 6.276 Surface 5,600’ 0.0383
7”x4-1/2” Liner 26 x 12.6 / L-80 / Hyd 563 3.958 5,600’ 17,637’ 0.0152
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / JFE Bear 3.958 Surface 6,390’ 0.0152
WELL INCLINATION DETAIL
KOP @ 400’
90° Hole Angle = @ 8,101’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. Top MD* Item ID
1 2,500 X Nipple 3.813”
2 5,600 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve 6.160”
3 5,600 Liner Top Packer 6.180”
4 5,750 X Nipple 3.813”
5 5,800 Production Packer 3.865”
6 5,850 X Nipple 3.813”
7 6,390 WLEG 6.160”
8 6,420 7” x 4-1/2” XO 3.958”
*All depths are approximate and are subject to change based on actual drilled
depths.
4-1/2” Sliding Sleeve Liner Detail
Size SPF Top (MD) Btm (MD) Type
4-1/2” SLV ~25 Sleeves Every 450’ NCS Sliding Sleeves
Page 7
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
PBU M-207 is a grassroots injector planned to be drilled in the Schrader Bluff OA sands. M-207 is part of a
multi-well program targeting the Schrader Bluff sand on PBU M-pad
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set into the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled. An injection liner will be ran and cemented in the open
hole section, followed by a 7” tieback and 4-1/2” tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately November 16, 2024, pending rig schedule.
Surface casing will be run to 6,422’ MD / 5,132’ 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” lateral to well TD
6. Run and cement 7” x 4-1/2” 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 geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
Page 8
Prudhoe Bay West
M-207 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 M-207.
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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Drilling Procedure
AOGCC Regulation Variance Requests:
Hilcorp would like to request a variance from 20 AAC 25.412.(b) which states:
“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 OA
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 ~5900’ MD. The X-nipple below the production packer will be
set at ~5850’ MD and the production packer will be ~50’ MD above the X nipple which puts it at ~5800’ MD /
~5005’ TVD. The surface casing shoe is planned at ~6422’ MD / ~5133’ TVD which means the planned packer
depth is ~622’ MD away. From a TVD standpoint, the production tubing packer is ~128’ 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.
Hilcorp would like to request a variance from AIO 25A Rule #4 which states:
“b. Within three months of start of injection in a new or converted injector, a step rate test and surveillance log
must be run for detection of fluids moving out of the approved injection stratum.”
The Polaris pool is unique among nearby Schraeder Bluff oil pools in its requirement to perform step-rate tests
and surveillance logs on all new or converted injectors to justify the maximum injection pressures for a given
well. The original justification for this change that was shared with the Commission in November 2003 were
step-rate tests on W-212 and S-215 which indicated injection pressures up to 0.8 psi/ft caused no detectable
migration of fluids outside of approved strata.
To date, all step-rate tests performed on injectors in the Polaris oil pool have indicated that the established
injection gradient of 0.8 psi/ft does not cause fluids to migrate out of zone. For M-207, Hilcorp is requesting that
0.8 psi/ft be established as the injection limit for this well without conducting the step-rate test and surveillance
log listed in AIO 25A Rule #4.
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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 and changing rams
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)
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Drilling Procedure
9.0 R/U and Preparatory Work
9.1 M-207 will utilize a 20” conductor on M-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).
x Cold mud temps are necessary to mitigate hydrate breakout
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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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 with 24 hour notice to witness. 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 – AOGCC Regulation requirement
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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Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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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 Schrader OA 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, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
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Drilling Procedure
x Gas hydrates are not present at PBU M-Pad. But be prepared for gas hydrates. In PBW
they have been encountered typically around 1660’ TVD (Base of Perm) to 2740’ TVD (Top
Ugnu) and below. Be prepared for hydrates:
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 pre-made 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, CF <1.0 :
x There are no wells with CF less than 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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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 – 9.8 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.
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.
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” TXP 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 Actual depth to be dependent upon base of permafrost and stage tool
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 Bowspring Centralizers only
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ 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, actual depth based upon base of permafrost)
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 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
9-5/8” 40# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”18860 20960 23060
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Drilling Procedure
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12.8 Continue running 9-5/8” surface casing
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 Actual length of 47# may change due to depth of permafrost as drilled
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 (6422'-1,000'-2,500') x 0.0558 bpf x 1.3 211.9 1188.7
Total Lead 211.9 1188.7 505.8
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):
13.8 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.
13.9 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.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 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.
13.11 Displacement calculation:
2500’ x 0.0732 bpf + (6,422’-120’-2500’) x .0758 bpf =
= 471.3 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.12 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.
13.13 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.
13.14 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.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
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
13.16 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.
13.17 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:
13.18 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.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. 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):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
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 3 316.3 1774.3
Total Lead 344.9 1934.8 763.2
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 269.9LeadTail
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.53 ft3/sk 1.16 ft3/sk
Mixed
Water 12.02 gal/sk 5.08 gal/sk
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Drilling Procedure
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 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.
13.28 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.
13.29 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.
13.30 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 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 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 4-1/2” x 7” 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.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 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
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.12 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” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout 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)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
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 GWD will be ran in the BHA to mitigate potential magnetic interference while drilling
past S pad wells
g
Submitpp(
casing test and FIT digital data to AOGCC.
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Drilling Procedure
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
15.10 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
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Drilling Procedure
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
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
15.14 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 Use ADR to stay in section. Reservoir plan is to stay in OA sand.
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Drilling Procedure
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 Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C, CF < 1.0:
x M-201 is a well in the SB Oba sand, we will have geologic separation from this well,
utilizing ADR to stay in the OA sand.
x Due to potential magnetic interference from M-201, GWD will be ran in the lateral
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.
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
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
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Drilling Procedure
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine.
15.19 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
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 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
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
x 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 & Cement 7” x 4-1/2” Injection Liner
16.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints
16.2 Well control preparedness: In the event of an influx of formation fluids while running the 7” x
4-1/2” liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint with
x 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2”
handling joint above TIW.
x -OR-
x 7“ XO installed on bottom, TIW valve in open position on top, 7” handling joint
above TIW.
x These joints shall be fully M/U and available prior to running the first joint of 4-1/2”
liner or 7” liner, respectively.
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.
16.3 R/U liner running equipment.
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.
16.4 Run 4-1/2” injection liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Confirm pipe dope with
TRS. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the
screens
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 Install jewelry as per the Running Order (From Completion Engineer post TD).
o ~25 NCS Sleeves every ~ 450’MD
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
Liner Torque – ftlbs
OD PPF Connection Minimum Optimum Maximum Yield
Torque
4-1/2 12.6 Hydril 563 3200 3700 5600 12600
7 26 Hydril 563 7800 9400 13700 39000
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Drilling Procedure
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Drilling Procedure
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Drilling Procedure
16.6. PU 4-1/2” NCS Airlock float sub before the 4-1/2” to 7” XO.
16.7. RU 7” running equipment and run 7” 26# H563 liner.
x ~820’ total. TOL ~5,600’ MD
x Centralized ½ joints, bowspring centralizers
16.8. Ensure to run enough 7” liner is to provide for sufficient overlap inside 9-5/8” casing tubing
packer completion. Tentative liner set depth ~ 5,600’ MD.
x 7” will be ran under the liner hanger for the production packer. Confirm with completion
engineer.
16.9. 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.
16.10. Before picking up Baker Flex Lock liner hanger / ZXP packer assembly, count the # of joints on
the pipe deck to make sure it coincides with the pipe tally.
16.11. M/U Baker Flex Lock liner hanger and ZXP liner top packer to liner.
x Confirm with OE any 7” joints between liner top packer and 4-1/2” liner for tubing
packer setting depth
x Liner running tool extension will need to be ran so liner wiper darts are positioned
at the 7” x 4-1/2” XO
16.12. 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.
16.13. 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 There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
x Use HWDP as needed for running liner
16.14. 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.
16.15. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
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Drilling Procedure
16.16. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.17. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.18. Rig up to pump down the work string with the rig pumps.
16.19. Pressure up to ~ 1200 psi to rupture air lock sub
x Airlock is rated for 3500 psi
x Hydrostatic with 9.0 -9.5 ppg brine is 2300 - 2500psi
x Rupture pressure will be 1000 – 1200 psi
16.20. Flood liner and fill drillpipe, setting pump limit to ~ 1000psi.
16.21. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating. Confirm all pressures with Baker
16.22. Prior to proceeding with cement job, 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.
16.23. Circulate and condition mud for cement job
16.24. RU Line sfor cement job if not already done so
16.25. Pump 30 bbls of 11ppg tunes spacer
16.26. Mix and pump cement as per plan
16.27. Cement volume based on OH annular volume + open hole excess (30%). Job will consist of
single slurry, TOC brought to the surface casing shoe, ~ 6,422’ MD
Cement Slurry Design (Single Stage Cement Job)
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
8-1/2" OH x 4-1/2" (17,637 - 6,422)' x 0.0505 bpf x 1.3 = 736.0 4129.0
4-1/2" Shoetrack 120' x 0.0152 bpf = 1.8 10.1
Total Tail 737.8 4139.1 2365.2Tail
Tail Slurry
System SoluCem
Density 15 lb/gal
Yield 1.75 ft3/sk
Mixed Water 7.88 gal/sk
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M-207 SB Injector
Drilling Procedure
16.28. After pumping cement, drop dart and displace cement with mud out of mud pits.
x (17,637’-120’-5600’) * .0152bpf = 181.1 bbl (Liner volume)
x Liner running tool at the 7x4-1/2” XO
x 5600’ * .0177 bpf (5” dp capacity) = 99.1 bbl (DP volume)
x = 280.2 bbl
16.29. Monitor returns and pump pressure closely while displacing, slow donw pumps when dart
latches onto liner wiper plug and when plug lands
16.30. Land liner wiper plug and pressure up to 500 psi over bump pressure. Bleed pressure and check
floats. If floats are not holding, shut in and hold 500 psi over bump pressure until cement builds
compressive strength.
Ensure to report the following on well report:
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, weight & type of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement, 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 time cement in place & calculated top of cement
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.
16.31. Continue pressuring up to 2,600 psi to set the Flex lock liner hanger. Hold for 5 minutes. Slack
off 20K lbs on the Flex Lock liner hanger to ensure the HRDE setting tool is in compression for
release from the liner hanger/packer. Continue pressuring up 4,000 psi to set the ZXP liner top
packer and release the HRDE running tool.
16.32. 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.
16.33. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
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Drilling Procedure
16.34. 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.
16.35. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.36. 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.
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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.
17.2 Notify AOGCC 24hrs prior to ram change
17.3 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.
17.4 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.
17.5 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.
17.6 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
Conform Torque with Casing Hand, below are guidelines
=Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs
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Drilling Procedure
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.
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.
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Drilling Procedure
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.
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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”, 12.6#, L-80 JFEBear 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 RIH with the following 4-1/2” completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 2x X Nipple
x 1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
x 1x X Nipple
x XXX joints, 4-1/2”, 12.6#, L-80 JFEBear
x WLEG
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Drilling Procedure
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Drilling Procedure
18.3 PU and MU the 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 source water follow diesel to freeze protect
for both tubing and IA to 2,500’ MD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting 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.
a. Work with Ops Engineer at Reg Tech to complete 10-426 Form for the initial MIT-T and
MIT-IA. This form must be completed regardless of AOGCC witness.
18.16 RDMO Innovation
i. POST RIG WELL WORK
x Slickline
o Pull B&R and RHC body
x Coil
o Contingent: Pull B&R and RHC body if SL unable to
o Shift injection sleeves open
o Contingent pump 15% HCl to breakdown cement behind injection sleeve
x Ops
o Put well on injection
o AOGCC witnessed MIT-IA once injection is stable
Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off thepgp
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA.
* State to witness MIT-IA to 3500 psi after 10 days of stabilized injection.
Page 47
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 48
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 49
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
21.0 Wellhead Schematic
Page 50
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
22.0 Days Vs Depth
Page 51
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
G1 Gravels Water/Ice 371.8 371.8 -319 164 8.46
SV6 Sand Ice 1717.6 1,634.8 -1582 719 8.46
BPRF Sand Ice 1983.8 1,868.8 -1816 822 8.46
SV5 Sand Gas Hydrates 2428.5 2,259.8 -2207 994 8.46
SV4 Sand Gas Hydrates 2651.4 2,455.8 -2403 1081 8.46
SV3 Sand Gas Hydrates 3075.7 2,828.8 -2776 1245 8.46
SV2 Sand 3248.6 2,980.8 -2928 1312 8.46
SV1 Sand 3600.1 3,289.8 -3237 1448 8.46
UG4 Sand Heavy Oil 3953.8 3,600.8 -3548 1584 8.46
UG4A Sand Heavy Oil 3998.2 3,639.8 -3587 1602 8.46
UG3 Sand Heavy Oil 4373.5 3,969.8 -3917 1747 8.46
UG1 Sand Heavy Oil 5005.4 4,516.8 -4464 1987 8.46
MF Sand Oil / Water 5688.1 4,956.8 -4904 2181 8.46
NB Sand Oil 5849.9 5,023.8 -4971 2210 8.46
OA_MF Sand Oil 6142.4 5,102.8 -5050 2245 8.46
OA (Heel) Sand Oil 6215.8 5,113.8 -5060 2250 8.46
SURFACE CASING Oil 6,422 5,132.8 -5080 2258 8.46
OA (Toe) 17,637 5,213.9 -5161 2294 8.46
M-207 wp10ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING EASTING Est.
Pressure Gradient
Page 52
Prudhoe Bay West
M-207 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 not been seen on PBU M Pad. Be prepared for them. They have been reported
between 1800’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free
penetrations of offset wells.
x Be prepared for gas hydrates
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.
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 CF less than1
Page 53
Prudhoe Bay West
M-207 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 M-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 54
Prudhoe Bay West
M-207 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 M-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 55
Prudhoe Bay West
M-207 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.
x 8-1/2” Lateral A/C, CF < 1.0:
x M-201 is a well in the SB Oba sand, we will have geologic separation from this well,
utilizing ADR to stay in the OA sand.
x Due to potential magnetic interference from M-201, GWD will be ran in the lateral for
further survey confidence
gy
Due to potential magnetic interference from M-201, GWD will be ran in the lateral forpg
further survey confidence
Page 56
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 57
Prudhoe Bay West
M-207 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 58
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 59
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
28.0 Casing Design
Page 60
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 61
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 62
Prudhoe Bay West
M-207 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
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0
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0
080016002400320040004800True Vertical Depth (1600 usft/in)-800 0 800 1600 2400 3200 4000 4800 5600 6400 7200 8000 8800 9600 10400 11200 12000 12800 13600 14400Vertical Section at 326.00° (1600 usft/in)M-207 wp05 Tgt1M-207 wp02 Tgt3M-207 wp02 Tgt4M-207 wp02 Tgt5M-207 wp02 Tgt6M-207 wp02 Tgt7M-207 wp02 Tgt8M-207 wp02 Tgt9M-207 wp02 Tgt11M-207 wp02 Tgt12M-207 wp06 tgt139 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750017637M-207 wp10Start Dir 3º/100' : 400' MD, 400'TVDEnd Dir : 1353.33' MD, 1314.56' TVDStart Dir 4º/100' : 4772.93' MD, 4320.95'TVDEnd Dir : 6272.53' MD, 5119.83' TVDBegin GeosteeringTotal Depth : 17637.14' MD, 5213.77' TVG1SV6BPRFSV5SV4SV3SV2SV1UG4UG4AUG3UG1MFNBOA_MFOA (Heel)Hilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: M-20726.40+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.005974568.78628208.41 70° 20' 19.5243 N148° 57' 34.7383 WSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 800.00 M-207 wp10 (M-207) GYD_Quest GWD800.00 6422.00 M-207 wp10 (M-207) 3_MWD+IFR2+MS+Sag6422.00 17637.14 M-207 wp10 (M-207) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation371.80 318.90 371.80 G11634.80 1581.90 1717.59 SV61868.80 1815.90 1983.75 BPRF2259.80 2206.90 2428.49 SV52455.80 2402.90 2651.43 SV42828.80 2775.90 3075.69 SV32980.80 2927.90 3248.59 SV23289.80 3236.90 3600.06 SV13600.80 3547.90 3953.80 UG43639.80 3586.90 3998.16 UG4A3969.80 3916.90 4373.52 UG34516.80 4463.90 5005.44 UG14956.80 4903.90 5688.04 MF5023.80 4970.90 5849.91 NB5102.80 5049.90 6142.39 OA_MF5113.80 5060.90 6215.80 OA (Heel)REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-207, True NorthVertical (TVD) Reference:M-207 as built @ 52.90usftMeasured Depth Reference:M-207 as built @ 52.90usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:MWell:Plan: M-207Wellbore:M-207Design:M-207 wp10CASING DETAILSTVD TVDSS MD SizeName5132.85 5079.95 6422.00 9-5/8 9 5/8" x 12 1/4"5213.77 5160.87 17637.14 4-1/2 4 1/2" 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 0.002 400.00 0.00 0.00 400.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 400' MD, 400'TVD3 800.00 12.00 310.00 797.08 26.83 -31.97 3.00 310.00 40.124 1353.33 28.46 303.17 1314.56 136.71 -187.47 3.00 -11.43 218.17 End Dir : 1353.33' MD, 1314.56' TVD5 4772.93 28.46 303.17 4320.95 1028.34 -1551.40 0.00 0.00 1720.06 Start Dir 4º/100' : 4772.93' MD, 4320.95'TVD6 6272.53 85.00 330.00 5119.83 1957.15 -2292.93 4.00 31.28 2904.74 End Dir : 6272.53' MD, 5119.83' TVD7 6422.53 85.00 330.00 5132.90 2086.55 -2367.64 0.00 0.00 3053.80 M-207 wp05 Tgt1 Begin Geosteering8 6539.19 88.50 330.00 5139.51 2187.41 -2425.87 3.00 0.00 3169.989 6849.99 89.16 320.70 5145.87 2442.74 -2602.36 3.00 -86.03 3480.3410 7751.89 89.16 320.70 5159.04 3140.57 -3173.57 0.00 0.00 4378.2911 7867.10 87.00 318.00 5162.90 3227.93 -3248.57 3.00 -128.77 4492.65 M-207 wp02 Tgt412 8101.25 90.97 323.79 5167.04 3409.49 -3396.13 3.00 55.64 4725.6913 8608.22 90.97 323.79 5158.44 3818.51 -3695.54 0.00 0.00 5232.2114 8646.98 90.61 323.11 5157.90 3849.64 -3718.62 2.00 -117.92 5270.92 M-207 wp02 Tgt515 8823.79 91.06 319.60 5155.32 3987.70 -3829.00 2.00 -82.65 5447.1116 9143.54 91.06 319.60 5149.40 4231.17 -4036.19 0.00 0.00 5764.8117 9593.86 89.32 333.00 5147.90 4604.96 -4285.46 3.00 97.35 6214.08 M-207 wp02 Tgt618 10160.25 89.30 349.99 5154.78 5140.06 -4464.54 3.00 90.17 6757.8419 10304.92 89.30 349.99 5156.55 5282.52 -4489.68 0.00 0.00 6890.0020 10438.25 89.54 346.00 5157.90 5412.90 -4517.40 3.00 -86.56 7013.59 M-207 wp02 Tgt721 10672.14 89.44 341.32 5159.98 5637.28 -4583.18 2.00 -91.21 7236.4022 11425.91 89.44 341.32 5167.30 6351.31 -4824.55 0.00 0.00 7963.3323 11681.08 90.29 335.00 5167.90 6588.05 -4919.42 2.50 -82.39 8212.64 M-207 wp02 Tgt824 11948.21 90.77 327.00 5165.42 6821.49 -5048.82 3.00 -86.53 8478.5325 12698.21 90.77 327.00 5155.35 7450.43 -5457.26 0.00 0.00 9228.3526 12815.54 87.25 327.00 5157.37 7548.81 -5521.15 3.00 180.00 9345.6327 13095.54 87.25 327.00 5170.81 7783.37 -5673.47 0.00 0.00 9625.2728 13483.87 90.56 315.83 5178.24 8086.32 -5915.22 3.00 -73.6310011.6129 14419.13 90.56 315.83 5169.02 8757.10 -6566.89 0.00 0.00 10932.1330 14524.90 90.65 319.00 5167.90 8834.96 -6638.45 3.00 88.44 11036.69 M-207 wp02 Tgt1131 15310.81 89.66 342.56 5165.74 9516.02 -7019.41 3.00 92.34 11814.3532 16267.64 89.66 342.56 5171.40 10428.84 -7306.23 0.00 0.00 12731.4933 16361.23 88.50 340.00 5172.90 10517.46 -7336.26 3.00 -114.44 12821.76 M-207 wp02 Tgt1234 16645.40 88.11 334.33 5181.31 10779.14 -7446.45 2.00 -94.02 13100.3135 17554.43 88.11 334.33 5211.29 11597.99 -7840.05 0.00 0.00 13999.2736 17637.14 88.46332.71 5213.77 11671.98 -7876.92 2.00 -77.81 14081.23 M-207 wp06 tgt13 Total Depth : 17637.14' MD, 5213.77' TVD
-750
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
South(-)/North(+) (1500 usft/in)-10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0
West(-)/East(+) (1500 usft/in)
M-207 wp06 tgt13
M-207 wp02 Tgt12
M-207 wp02 Tgt11
M-207 wp02 Tgt9
M-207 wp02 Tgt8
M-207 wp02 Tgt7
M-207 wp02 Tgt6
M-207 wp02 Tgt5
M-207 wp02 Tgt4
M-207 wp02 Tgt3
M-207 wp05 Tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
25050075010001250150017502000225025002750300032503500375040004250450047505000
5 2 1 4
M -2 0 7 w p 1 0
Start Dir 3º/100' : 400' MD, 400'TVD
End Dir : 1353.33' MD, 1314.56' TVD
Start Dir 4º/100' : 4772.93' MD, 4320.95'TVD
End Dir : 6272.53' MD, 5119.83' TVD
Begin Geosteering
Total Depth : 17637.14' MD, 5213.77' TVD
CASING DETAILS
TVD TVDSS MD Size Name
5132.85 5079.95 6422.00 9-5/8 9 5/8" x 12 1/4"
5213.77 5160.87 17637.14 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: M
Well: Plan: M-207
Wellbore: M-207
Plan: M-207 wp10
WELL DETAILS: Plan: M-207
26.40
+N/-S +E/-W Northing Easting Latittude Longitude
0.00 0.00 5974568.78 628208.41 70° 20' 19.5243 N 148° 57' 34.7383 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: M-207, True North
Vertical (TVD) Reference: M-207 as built @ 52.90usft
Measured Depth Reference:M-207 as built @ 52.90usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650Measured Depth (700 usft/in)MNo-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: M-207 NAD 1927 (NADCON CONUS)Alaska Zone 0426.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.005974568.78628208.4170° 20' 19.5243 N148° 57' 34.7383 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-207, True NorthVertical (TVD) Reference:M-207 as built @ 52.90usftMeasured Depth Reference:M-207 as built @ 52.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 M-207 wp10 (M-207) GYD_Quest GWD800.00 6422.00 M-207 wp10 (M-207) 3_MWD+IFR2+MS+Sag6422.00 17637.14 M-207 wp10 (M-207) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650Measured Depth (700 usft/in)M-13M-13AM-15M-201M-14M-205GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 17637.14Project: Prudhoe BaySite: MWell: Plan: M-207Wellbore: M-207Plan: M-207 wp10Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name5132.85 5079.95 6422.00 9-5/8 9 5/8" x 12 1/4"5213.77 5160.87 17637.14 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000Measured Depth (1200 usft/in)S-110S-110BM-201S-124M-200S-13AS-13APB1M-204S-41AL1S-41S-41L1S-41AM-206M-206 wp09M-205No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: M-207 NAD 1927 (NADCON CONUS)Alaska Zone 0426.40+N/-S +E/-W Northing EastingLatittudeLongitude0.000.005974568.78628208.41 70° 20' 19.5243 N 148° 57' 34.7383 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: M-207, True NorthVertical (TVD) Reference:M-207 as built @ 52.90usftMeasured Depth Reference:M-207 as built @ 52.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-09-24T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 800.00 M-207 wp10 (M-207) GYD_Quest GWD800.00 6422.00 M-207 wp10 (M-207) 3_MWD+IFR2+MS+Sag6422.00 17637.14 M-207 wp10 (M-207) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800 17400 18000Measured Depth (1200 usft/in)S-110BM-201S-13AS-13APB1M-205GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 17637.14Project: Prudhoe BaySite: MWell: Plan: M-207Wellbore: M-207Plan: M-207 wp10Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name5132.85 5079.95 6422.00 9-5/8 9 5/8" x 12 1/4"5213.77 5160.87 17637.14 4-1/2 4 1/2" x 8 1/2"
1
Dewhurst, Andrew D (OGC)
From:Guhl, Meredith D (OGC)
Sent:Friday, 15 November, 2024 09:28
To:Dewhurst, Andrew D (OGC)
Cc:Davies, Stephen F (OGC); Rixse, Melvin G (OGC)
Subject:RE: PBU M-206, PTD 224-130, Field Data Available on Hilcorp SFTP Site
Hi Andy,
Data is downloaded and available here: G:\AOGCC\Wells\z224\2241300_PBU_M-206\Field Logs for M-207 review .
Cheers,
Meredith
From: AK_GeoTech <AK_GeoTEch@hilcorp.com>
Sent: Friday, November 15, 2024 9:21 AM
To: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>
Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>;
Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; AK_GeoTech
<AK_GeoTEch@hilcorp.com>
Subject: PBU M-206, PTD 224-130, Field Data Available on Hilcorp SFTP Site
Hello Meredith,
I have uploaded the Field Data and Cement Reports for PBU M-206 to the Hilcorp SFTP Site.
Well: PBU M-206
PTD: 224-130
API: 50-029-23804-00-00
SFTP Contents:
x Field LWD Formation Evaluation Logs (10/21/2024 to 11/05/2024)
ROP, BaseStar & ABG Gamma Ray, ResiStar & StrataStar Resistivity
Horizontal & Invert/Revert Presentations (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Cement Reports
Please let me know if there are any further information requested, questions or concerns.
David Douglas
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͵ͺͲͲǡͳͶͲͲȁ ǡͻͻͷͲ͵
Ǥ̷ Ǥ
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.
2
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Friday, November 15, 2024 7:46 AM
To: David Douglas <David.Douglas@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>; Joseph Engel
<jengel@hilcorp.com>
Subject: Fwd: [EXTERNAL] PBU M-206, PTD 224-130, Data requested
Dave,
Could you please provide Meredith the requested logs? Anything you can do to get them to her ASAP would be
appreciated. Thanks!
Begin forwarded message:
From: "Guhl, Meredith D (OGC)" <meredith.guhl@alaska.gov>
Date: November 15, 2024 at 7:23:04ௗAM AKST
To: Joseph Lastufka <joseph.lastufka@hilcorp.com>
Cc: "Dewhurst, Andrew D (OGC)" <andrew.dewhurst@alaska.gov>, "Davies, Stephen F (OGC)"
<steve.davies@alaska.gov>, "Rixse, Melvin G (OGC)" <melvin.rixse@alaska.gov>
Subject: [EXTERNAL] PBU M-206, PTD 224-130, Data requested
Hello Joe,
As part of the review in support of the PTD for PBU M-207, the AOGCC is requesting data from the
recently drilled PBU M-206 well. We realize that field data may be the only data available at this
time. Please provide:
1. Directional survey
2. LWD logs
3. Cementing reports
Please note that this field-quality information does not meet the final well reporting requirements
of 20 AAC 25.071, and the submission of final data is still required along the normal routes.
Field data should be directed by email or ftps site to me, and I will facilitate download and
accessibility for senior AOGCC staff.
Thank you,
Meredith
Meredith Guhl (she/her)
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil
and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may
contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may
violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders.
3
forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235
or meredith.guhl@alaska.gov.
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 d issemination, 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.
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
POLARIS OIL
PBU M-207
224-141
PRUDHOE BAY
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN POL M-207Initial Class/TypeSER / PENDGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2241410PRUDHOE BAY, POLARIS OIL - 640160NA1Permit fee attachedYesADL028260 and ADL0282572Lease number appropriateYes3Unique well name and numberYesPRUDHOE BAY, POLARIS OIL - 640160 - governed by CO 484A4Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitYesAIO 25A14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)No16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes20" 129.5# X-52 driven to 80'18Conductor string providedYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19Surface casing protects all known USDWsYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20CMT vol adequate to circulate on conductor & surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21CMT vol adequate to tie-in long string to surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22CMT will cover all known productive horizonsYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23Casing designs adequate for C, T, B & permafrostYesHilcorp Innvovation rig has adequate tankage and good trucking support24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows 1 close approaches with minimal HSE risk and geological separation.26Adequate wellbore separation proposedYes16" Diverter27If diverter required, does it meet regulationsYesAll fluids overbalanced to expected pore pressure.28Drilling fluid program schematic & equip list adequateYes1 annular, 3 ram stack tested to 3000 psi.29BOPEs, do they meet regulationYes13-5/8" , 5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)YesInnovation has 10X 2-9/16"" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/8" remote hyd choke31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownYesPBU M pad has no H2S history. Monitoring will be required.33Is presence of H2S gas probableYes34Mechanical condition of wells within AOR verified (For service well only)NoH2S measures required.35Permit can be issued w/o hydrogen sulfide measuresYesAnticipating normally pressured reservoir. MPD available for production hole.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate18-Nov-24ApprMGRDate14-Nov-24ApprADDDate18-Nov-24AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublicCommissionerDateJLC 11/19/2024*&:
